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Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2011
Summary of Significant Accounting Policies  
Use of Estimates

Use of Estimates

 

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We make significant estimates with respect to (i) purchases and sales accruals, (ii) estimated fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets, (iii) mark-to-market gains and losses on derivative instruments (pursuant to guidance issued by the FASB regarding fair value measurements), (iv) accruals and contingent liabilities, (v) equity compensation plan accruals, (vi) property and equipment and depreciation expense and (vii) allowance for doubtful accounts. Although we believe these estimates are reasonable, actual results could differ from these estimates.
Revenue Recognition

Revenue Recognition

 

Supply and Logistics Segment Revenues.  Revenues from sales of crude oil, LPG and refined products are recognized at the time title to the product sold transfers to the purchaser, which occurs upon delivery of the product to the purchaser or its designee. Sales of crude oil, LPG and refined products consist of outright sales contracts and buy/sell arrangements as well as exchanges. Inventory purchases and sales under buy/sell transactions are treated as inventory exchanges and are presented net within Supply and Logistics segment revenues in our consolidated statements of operations.

 

Additionally, we may utilize derivatives in connection with the transactions described above. For commodity derivatives that are designated as cash flow hedges, derivative gains and losses are deferred to AOCI and recognized in revenues in the periods during which the underlying physical hedged transaction impacts earnings. Also, the ineffective portion of the change in fair value of cash flow hedges is recognized in revenues each period along with the change in fair value of derivatives that do not qualify for or are not designated for hedge accounting.

 

Transportation Segment Revenues.  Revenues from pipeline tariffs and fees are associated with the transportation of crude oil and refined products at a published tariff, as well as revenues associated with line leases for committed space on a particular system that may or may not be utilized. Tariff revenues are recognized either at the point of delivery or at the point of receipt pursuant to specifications outlined in the regulated and non-regulated tariffs. Revenues associated with line-lease fees are recognized in the month to which the lease applies, whether or not the space is actually utilized. The majority of our pipeline tariff and fee revenues are based on actual volumes and rates. As is common in the industry, our tariffs incorporate a loss allowance factor that is intended to, among other things, offset losses due to evaporation, measurement and other losses in transit. We value the variance of allowance volumes to actual losses at the estimated net realizable value (including the impact of gains and losses from derivative related activities) at the time the variance occurred and the result is recorded as either an increase or decrease to tariff revenues. In addition, we have certain agreements that require counterparties to ship a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume is shipped (pursuant to specifications outlined in the tariffs) or when the counterparty’s ability to make up the minimum volume has expired.

 

Facilities Segment Revenues.  Our facilities segment operations generally consist of fee-based activities associated with providing storage, terminalling and throughput services for crude oil, refined products, LPG and natural gas, LPG fractionation and isomerization services and natural gas processing services. Revenues generated in this segment include (i) storage fees that are generated when we lease storage capacity, (ii) terminalling fees, or throughput fees, that are generated when we receive crude oil, refined products or LPG from one connecting pipeline and redeliver the applicable product to another connecting carrier, (iii) hub service fees associated with natural gas park and loan activities, interruptible storage services and wheeling and balancing services, (iv) revenues from the sale of natural gas, (v) fees from LPG fractionation and isomerization and (vi) fees from gas processing services.  We generate revenue through a combination of month-to-month and multi-year leases and processing arrangements.  Storage fees resulting from short-term and long-term contracts are typically recognized in revenue ratably over the term of the contract regardless of the actual storage capacity utilized. Terminal fees are recognized as the crude oil, LPG or refined product exits the terminal and is delivered to the connecting carrier or third-party terminal. Hub service fees are recognized in the period the natural gas moves across our header system. Fees from LPG fractionation, isomerization services and gas processing services are recognized in the period when the services are performed.  Revenues associated with the sale of natural gas are recognized at the time title to the product sold transfers to the purchaser or its designee. In addition, we have certain agreements that require counterparties to throughput a minimum volume over an agreed upon period. Revenue is recognized at the latter of when the volume exits the terminal or when the counterparty’s ability to make up the minimum volume has expired.
Purchases and Related Costs

Purchases and Related Costs

 

Purchases and related costs include (i) the cost of crude oil, LPG, natural gas and refined products obtained in outright purchases, (ii) fees incurred for third-party transportation and storage, whether by pipeline, truck, rail, ship or barge, (iii) interest cost attributable to borrowings for inventory stored in a contango market and (iv) performance-related bonus accruals. These costs are recognized when incurred except in the case of products purchased, which are recognized at the time title transfers to us.
Field Operating Costs and General and Administrative Expenses

Field Operating Costs and General and Administrative Expenses

 

Field operating costs consist of various field operating expenses, including fuel and power costs, telecommunications, payroll and benefit costs (including equity compensation expense) for truck drivers and field personnel, third-party trucking transportation costs for our U.S. crude oil operations, maintenance and integrity management costs, regulatory compliance, environmental remediation, insurance, vehicle leases, and property taxes. General and administrative expenses consist primarily of payroll and benefit costs (including equity compensation expense), certain information systems and legal costs, office rent, contract and consultant costs and audit and tax fees.
Foreign Currency Transactions

Foreign Currency Transactions

 

Certain of our subsidiaries use the Canadian dollar as their functional currency. Assets and liabilities of subsidiaries with a Canadian dollar functional currency are translated at period-end rates of exchange, and revenues and expenses are translated at average exchange rates prevailing for each month. The resulting translation adjustments are made directly to a separate component of other comprehensive income in Partners’ Capital reflected on our consolidated balance sheet.

 

Certain of our subsidiaries also enter into transactions and have monetary assets and liabilities that are denominated in a currency other than the entities’ respective functional currencies. Gains and losses from the revaluation of foreign currency transactions and monetary assets and liabilities are included in the consolidated statements of operations. The revaluation of foreign currency transactions and monetary assets and liabilities resulted in a loss of approximately $2 million for the year ended December 31, 2011 and gains of approximately $2 million and $13 million for the years ended December 31, 2010 and 2009, respectively.
Cash and Cash Equivalents

Cash and Cash Equivalents

 

Cash and cash equivalents consist of all unrestricted demand deposits and funds invested in highly liquid instruments with original maturities of three months or less and typically exceed federally insured limits. We periodically assess the financial condition of the institutions where these funds are held and believe that our credit risk is minimal. In accordance with our policy, outstanding checks are classified as accounts payable rather than negative cash. As of December 31, 2011 and 2010, accounts payable included approximately $58 million and $40 million, respectively, of outstanding checks that were reclassified from cash and cash equivalents.
Restricted Cash

Restricted Cash

 

Restricted cash at December 31, 2010 consisted of $20 million held by an escrow agent in connection with PNG’s February 2011 acquisition of SG Resources. See Note 3 for further discussion of this acquisition. We had no restricted cash at December 31, 2011.
Accounts Receivable

Accounts Receivable

 

Our accounts receivable are primarily from purchasers and shippers of crude oil and, to a lesser extent, purchasers of LPG, refined products and natural gas storage. These purchasers include, but are not limited to refineries, producers, marketing and trading companies and financial institutions that are active in the physical and financial commodity markets. The majority of our accounts receivable relate to our crude oil supply and logistics activities that can generally be described as high volume and low margin activities, in many cases involving exchanges of crude oil volumes.

 

To mitigate credit risks related to our accounts receivable, we have in place a rigorous credit review process.  We closely monitor market conditions in order to make a determination with respect to the amount, if any, of credit to be extended to any given customer and the form and amount of financial performance assurances we require. Such financial assurances are commonly provided to us in the form of standby letters of credit, “parental” guarantees or advance cash payments. At December 31, 2011 and 2010, we had received approximately $186 million and $197 million, respectively, of advance cash payments from third parties to mitigate credit risk. In addition, we enter into netting arrangements (contractual agreements that allow us and the counterparty to offset receivables and payables between the two) that cover a significant part of our transactions and also serve to mitigate credit risk.

 

We review all outstanding accounts receivable balances on a monthly basis and record a reserve for amounts that we expect will not be fully recovered. We do not apply actual balances against the reserve until we have exhausted substantially all collection efforts. At December 31, 2011 and 2010, substantially all of our accounts receivable (net of allowance for doubtful accounts) were less than 30 days past their scheduled invoice date. Our allowance for doubtful accounts receivable totaled approximately $5 million at both December 31, 2011 and 2010. Although we consider our allowance for doubtful trade accounts receivable to be adequate, actual amounts could vary significantly from estimated amounts.
Inventory, Linefill, Base Gas and Long-term Inventory

Inventory, Linefill, Base Gas and Long-term Inventory

 

Inventory primarily consists of crude oil, LPG and natural gas in pipelines, storage facilities and rail cars that are valued at the lower of cost or market, with cost determined using an average cost method within specific inventory pools.

 

At the end of each reporting period, we assess the carrying value of our inventory and make any adjustments necessary to reduce the carrying value to the applicable net realizable value.  During 2011, 2010 and 2009, we did not recognize material writedowns of such inventory.  Linefill, base gas and minimum working inventory requirements in assets we own are recorded at historical cost and consist of crude oil, LPG and natural gas.  We classify as linefill or base gas (i) our proportionate share of barrels used to fill a pipeline such that when an incremental barrel is pumped into or enters a pipeline it forces product out at another location, (ii) barrels that represent the minimum working requirements in tanks that we own and (iii) natural gas required to maintain the minimum operating pressure of natural gas storage facilities we own.  During 2011, 2010 and 2009, we recorded gains of approximately $21 million, $21 million and $4 million, respectively, on the sale of pipeline linefill for proceeds of approximately $56 million, $72 million and $24 million, respectively.

 

Minimum working inventory requirements in third-party assets and other working inventory in our assets that is needed for our commercial operations are included within specific inventory pools in inventory (a current asset) in determining the average cost of operating inventory. At the end of each period, we reclassify the inventory not expected to be liquidated within the succeeding twelve months out of inventory, at average cost, and into long-term inventory, which is reflected as a separate line item within other assets on the consolidated balance sheet.

 

Inventory, linefill, base gas and long-term inventory consisted of the following (barrels in thousands, natural gas volumes in thousands of Mcf and total value in millions):

 

 

 

December 31, 2011

 

December 31, 2010

 

 

 

Volumes

 

Unit of
Measure

 

Total Value

 

Price/
Unit (1)

 

Volumes

 

Unit of
Measure

 

Total Value

 

Price/
Unit (1)

 

Inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

5,361

 

barrels

 

$

483

 

$

90.10

 

14,132

 

barrels

 

$

1,100

 

$

77.84

 

LPG

 

6,885

 

barrels

 

438

 

$

63.62

 

7,395

 

barrels

 

366

 

$

49.49

 

Natural gas (2)

 

16,170

 

Mcf

 

51

 

$

3.15

 

13

 

Mcf

 

—

 

$

3.87

 

Other

 

N/A

 

 

 

6

 

N/A

 

N/A

 

 

 

25

 

N/A

 

Inventory subtotal

 

 

 

 

 

978

 

 

 

 

 

 

 

1,491

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Linefill and base gas

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

9,366

 

barrels

 

514

 

$

54.88

 

9,159

 

barrels

 

478

 

$

52.19

 

Natural gas (2)

 

14,105

 

Mcf

 

48

 

$

3.40

 

11,194

 

Mcf

 

37

 

$

3.31

 

LPG

 

31

 

barrels

 

2

 

$

64.52

 

77

 

barrels

 

4

 

$

51.95

 

Linefill and base gas subtotal

 

 

 

 

 

564

 

 

 

 

 

 

 

519

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term inventory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil

 

1,714

 

barrels

 

127

 

$

74.10

 

1,761

 

barrels

 

128

 

$

72.69

 

LPG

 

150

 

barrels

 

8

 

$

53.33

 

505

 

barrels

 

26

 

$

51.49

 

Long-term inventory subtotal

 

 

 

 

 

135

 

 

 

 

 

 

 

154

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

$

1,677

 

 

 

 

 

 

 

$

2,164

 

 

 

 

(1)                                     Price per unit of measure represents a weighted average associated with various grades, qualities and locations; accordingly, these prices may not coincide with any published benchmarks for such products.

 

(2)                                     The volumetric ratio of Mcf of natural gas to crude Btu equivalent is 6:1; thus, natural gas volumes can be approximately converted to barrels by dividing by 6.
Property and Equipment

Property and Equipment

 

In accordance with our capitalization policy, costs associated with acquisitions and improvements that expand our existing capacity, including related interest costs, are capitalized. For the years ended December 31, 2011, 2010 and 2009, capitalized interest was $25 million, $16 million and $15 million, respectively. We also capitalize expenditures for the replacement of partially or fully depreciated assets in order to maintain the service capability, level of production and/or functionality of our existing assets. Repair and maintenance expenditures incurred in order to maintain the day to day operation of our existing assets are expensed as incurred.

 

Property and equipment, net is stated at cost and consisted of the following (in millions):

 

 

 

Estimated Useful

 

December 31,

 

 

 

Lives (Years)

 

2011

 

2010

 

Crude oil pipelines and facilities

 

10 - 70

 

$

4,467

 

$

4,303

 

Storage and terminal facilities

 

30 - 70

 

3,385

 

2,740

 

Trucking equipment and other

 

3 - 15

 

110

 

106

 

Construction in progress

 

—

 

693

 

304

 

Office property and equipment

 

2 - 50

 

99

 

95

 

Land and other

 

N/A

 

275

 

266

 

 

 

 

 

9,029

 

7,814

 

Accumulated depreciation

 

 

 

(1,289

)

(1,123

)

 

 

 

 

 

 

 

 

Property and equipment, net

 

 

 

$

7,740

 

$

6,691

 

 

Depreciation expense for the years ended December 31, 2011, 2010 and 2009 was $196 million, $235 million and $216 million, respectively.

 

We calculate our depreciation using the straight-line method, based on estimated useful lives and salvage values of our assets. During 2011 and 2010, we extended the depreciable lives of several of our crude oil and other storage facilities and pipeline systems based on an ongoing review to assess the useful lives of our property and equipment and to adjust those lives, if appropriate, to reflect current expectations given actual experience and current technology. These depreciable life extensions will prospectively reduce depreciation expense. For the years ended December 31, 2011 and 2010, these extensions reduced depreciation expense by approximately $60 million (incrementally by $37 million as compared to the prior year) and $23 million, respectively.

 

We also classify gains and losses on sales of assets and asset impairments as a component of depreciation and amortization in the consolidated statements of operations. During the years ended 2011 and 2010, we recognized losses on disposition of certain assets and impairments for assets taken out of service of approximately $11 million and $13 million, respectively.
Equity Method of Accounting

Equity Method of Accounting

 

Our investments in the following entities are accounted for under the equity method of accounting:

 

Entity

 

Type of Operation

 

Our Ownership
Interest

 

Settoon Towing, LLC

 

Barge Transportation Services

 

50

%

White Cliffs Pipeline, L.L.C.

 

Crude Oil Pipeline

 

34

%

Frontier Pipeline Company

 

Crude Oil Pipeline

 

22

%

Butte Pipe Line Company

 

Crude Oil Pipeline

 

22

%

 

We do not consolidate any part of the assets or liabilities of our equity investees. Our share of net income or loss is reflected as one line item on the income statement entitled “Equity earnings in unconsolidated entities” and will increase or decrease, as applicable, the carrying value of our investments in unconsolidated entities on the balance sheet. In addition, we include a proportionate share of our equity method investees’ unrealized gains and losses in other comprehensive income on our consolidated balance sheet.  We also adjust our investment balances in these investees by the like amount.  Distributions to the Partnership will reduce the carrying value of our investments and will be reflected on our cash flow statement netted against equity in earnings. In turn, contributions will increase the carrying value of our investments and will be reflected on our cash flow statement within investing activities.
Noncontrolling Interest

Noncontrolling Interests

 

We account for noncontrolling interests in subsidiaries in accordance with FASB guidance specific to noncontrolling interests.  FASB guidance requires all entities to report noncontrolling interests in subsidiaries as a component of equity in the consolidated financial statements. Noncontrolling interest represents the portion of assets and liabilities in a consolidated subsidiary that is owned by a third-party.  See Note 5 for additional discussion regarding our noncontrolling interests.
Asset Retirement Obligations

Asset Retirement Obligations

 

FASB guidance establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including estimates related to (i) the time of the liability recognition, (ii) initial measurement of the liability, (iii) allocation of asset retirement cost to expense, (iv) subsequent measurement of the liability and (v) financial statement disclosures. FASB guidance also requires that the cost for asset retirement should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.

 

Some of our assets, primarily related to our transportation and facilities segments, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned. These obligations include varying levels of activity including disconnecting inactive assets from active assets, cleaning and purging assets, and in some cases, completely removing the assets and returning the land to its original state. These assets have been in existence for many years and with regular maintenance will continue to be in service for many years to come. It is not possible to predict when demand for these transportation or storage services will cease, and we do not believe that such demand will cease for the foreseeable future. Accordingly, we believe the date when these assets will be abandoned is indeterminate. With no reasonably determinable abandonment date, we cannot reasonably estimate the fair value of the associated asset retirement obligations. We will record asset retirement obligations for these assets in the period in which sufficient information becomes available for us to reasonably determine the settlement dates.

 

A small portion of our contractual or regulatory obligations is related to assets that are inactive or that we plan to take out of service and, although the ultimate timing and costs to settle these obligations are not known with certainty, we have recorded a reasonable estimate of these obligations. We have estimated that the fair value of these obligations was approximately $9 million and $5 million, respectively, at December 31, 2011 and 2010.
Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

 

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value in accordance with FASB guidance with respect to the accounting for the impairment or disposal of long-lived assets. Under this guidance, a long-lived asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized.

 

We periodically evaluate property and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows.  The subjective assumptions used to determine the existence of an impairment in carrying value include:

 

·                  whether there is an indication of impairment;

 

·                  the grouping of assets;

 

·                  the intention of “holding,” “abandoning” or “selling” an asset;

 

·                  the forecast of undiscounted expected future cash flow over the asset’s estimated useful life; and

 

·                  if an impairment exists, the fair value of the asset or asset group.

 

During 2011, 2010 and 2009, impairments of approximately $5 million, $13 million and less than $1 million, respectively, were recognized related predominately to assets that were taken out of service. These assets did not support spending the capital necessary to continue service and, in most instances, we utilized other assets to handle these activities.
Goodwill

Goodwill

 

Goodwill represents the future economic benefits arising from assets acquired in a business combination that are not individually identified and separately recognized. In accordance with FASB guidance, we test goodwill at least annually (as of June 30) and on an interim basis if a triggering event occurs, such as an adverse change in business climate, to determine whether an impairment has occurred. Goodwill is tested for impairment at a level of reporting referred to as a reporting unit. A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management. Our reporting units are our operating segments. FASB guidance requires a two step approach to testing goodwill for impairment. In Step 1, we compare the fair value of the reporting unit with the respective book values, including goodwill, by using an income approach based on a discounted cash flow analysis. This approach requires us to make long-term forecasts of future revenues, expenses and other expenditures. Those forecasts require the use of various assumptions and estimates, the most significant of which are net revenues (total revenues less purchases and related costs), operating expenses, general and administrative expenses and the weighted average cost of capital. Fair value of the reporting units is determined using significant unobservable inputs, or level 3 inputs in the fair value hierarchy. When the fair value is greater than book value, then the reporting unit’s goodwill is not considered impaired. If the book value is greater than fair value, then we proceed to Step 2. In Step 2, we compare the implied fair value of the reporting unit’s goodwill with the book value. A goodwill impairment loss is recognized if the carrying amount exceeds its fair value.

 

Through Step 1 of our annual testing of goodwill for potential impairment, which also includes a sensitivity analysis regarding the excess of our reporting unit’s fair value over book value, we determined that the fair value of each reporting unit was substantially greater than its respective book value, and therefore goodwill was not considered impaired.  We will continue to monitor various potential indicators (including the financial markets) to determine if a triggering event occurs and will perform another goodwill impairment analysis if necessary.

 

The table below reflects our changes in goodwill (in millions):

 

 

 

Transportation

 

Facilities

 

Supply & Logistics

 

Total (1)

 

 

 

 

 

 

 

 

 

 

 

Balance at December 31, 2009

 

$

608

 

$

308

 

$

371

 

$

1,287

 

 

 

 

 

 

 

 

 

 

 

2010 Goodwill Related Activity:

 

 

 

 

 

 

 

 

 

Nexen acquisition

 

18

 

—

 

54

 

72

 

Purchase price accounting adjustments (2)

 

3

 

—

 

—

 

3

 

Foreign currency translation adjustments

 

11

 

—

 

3

 

14

 

Balance at December 31, 2010

 

$

640

 

$

308

 

$

428

 

$

1,376

 

 

 

 

 

 

 

 

 

 

 

2011 Goodwill Related Activity:

 

 

 

 

 

 

 

 

 

Southern Pines acquisition (2)

 

—

 

301

 

—

 

301

 

Gardendale Gathering System acquisition(2)

 

155

 

—

 

—

 

155

 

Foreign currency translation adjustments

 

(5

)

—

 

(1

)

(6

)

Purchase price accounting adjustments and other (2)

 

28

 

—

 

—

 

28

 

Balance at December 31, 2011

 

$

818

 

$

609

 

$

427

 

$

1,854

 

 

(1)                                     As of December 31, 2011, the total carrying amount of goodwill is net of approximately $3 million of accumulated impairment losses.

 

(2)                                     Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation. This preliminary goodwill balance may be adjusted when the purchase price allocation is finalized.  See Note 3 for additional discussion of our acquisitions.
Other Assets, Net

Other Assets, Net

 

Other assets, net of accumulated amortization, consist of the following (in millions):

 

 

 

December 31,

 

 

 

2011

 

2010

 

Debt issue costs

 

$

53

 

$

47

 

Fair value of derivative instruments

 

20

 

20

 

Intangible assets

 

498

 

311

 

Other

 

59

 

58

 

 

 

630

 

436

 

Accumulated amortization

 

(84

)

(54

)

 

 

$

546

 

$

382

 

 

Costs incurred in connection with the issuance of long-term debt and amendments to our credit facilities are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the “effective interest” method of amortization. Fully amortized debt issue costs and the related accumulated amortization are written off in conjunction with the refinancing or termination of the applicable debt arrangement. We capitalized debt issue costs of approximately $18 million and $7 million in 2011 and 2010, respectively. Approximately $11 million of gross debt issue costs were removed from our Consolidated Balance Sheet during 2011, primarily related to the restructuring of our credit facilities in August 2011.

 

Amortization expense related to other assets (including finite-lived intangible assets) for the three years ended December 31, 2011, 2010 and 2009 was $44 million, $22 million and $19 million, respectively. Our amortization expense for finite-lived intangible assets for the years ended December 31, 2011, 2010 and 2009 was $36 million, $14 million and $14 million, respectively.
Intangible Assets

Intangible assets that have finite lives are tested for impairment when events or circumstances indicate that the carrying value may not be recoverable. Our intangible assets that have finite lives consist of the following (in millions):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2011

 

December 31, 2010

 

 

 

Estimated Useful

 

 

 

Accumulated

 

 

 

 

 

Accumulated

 

 

 

 

 

Lives (Years)

 

Cost

 

Amortization

 

Net

 

Cost

 

Amortization

 

Net

 

Customer contracts and relationships

 

1-20

 

$

426

 

$

(61

)

$

365

 

$

221

 

$

(34

)

$

187

 

Property tax abatement

 

7-13

 

38

 

(6

)

32

 

23

 

(2

)

21

 

Other agreements

 

30-70

 

26

 

(1

)

25

 

22

 

(1

)

21

 

Emission reduction credits (1)

 

N/A

 

8

 

—

 

8

 

45

 

—

 

45

 

 

 

 

 

$

498

 

$

(68

)

$

430

 

$

311

 

$

(37

)

$

274

 

 

(1)                                     Emission reduction credits are finite-lived and are subject to surrender from the date that they are first utilized. During 2011, approximately $37 million of emission reduction credits were surrendered as part of the permitting process associated with facility construction and were reclassified into construction in progress, which is included within Property and equipment on our Consolidated Balance Sheet.

 

The increase in intangible assets from December 31, 2010 was primarily related to intangibles acquired in connection with the Southern Pines, Gardendale Gathering System and Western acquisitions. See Note 3 for further discussion of our acquisition activities.

 

We estimate that our amortization expense related to finite-lived intangible assets for the next five years will be as follows (in millions):

 

2012

 

$

50

 

2013

 

$

47

 

2014

 

$

44

 

2015

 

$

41

 

2016

 

$

36

 
Environmental Matters

Environmental Matters

 

We record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We do not discount our environmental remediation liabilities to present value. We also record receivables for amounts recoverable from insurance or from third parties under indemnification agreements in the period that we determine the costs are probable of recovery.

 

We expense expenditures that relate to an existing condition caused by past operations that do not contribute to current or future profitability. We record environmental liabilities assumed in business combinations based on the estimated fair value of the environmental obligations caused by past operations of the acquired company. See Note 11 for further discussion of environmental remediation matters.
Income and Other Taxes

Income and Other Taxes

 

We estimate (i) income taxes in the jurisdictions in which we operate, (ii) net deferred tax assets and liabilities based on temporary differences that are expected to be recovered or settled at the enacted tax rates expected in future periods, (iii) valuation allowances for deferred tax assets and (iv) contingent tax liabilities for estimated exposures related to our current tax positions.

 

We adopted the provisions of the FASB guidance related to accounting for uncertainty in income taxes on January 1, 2007. Pursuant to this guidance, we must recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based on the technical merits of the tax position and also the past administrative practices and precedents of the taxing authority. As of December 31, 2011 and 2010, we have not recognized any material amounts in connection with uncertainty in income taxes.

 

See Note 7 for discussion of U.S. federal and state taxes and Canadian federal and provincial taxes.
Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

 

We record all open derivative instruments on the balance sheet as either assets or liabilities measured at their fair value pursuant to FASB guidance. This guidance requires that changes in the fair value of derivative instruments be recognized currently in earnings unless specific hedge accounting criteria are met.  For cash flow hedges, the effective portion of the change in fair value is deferred in AOCI and reclassified into earnings when the underlying transaction affects earnings.  For fair value hedges, the change in fair value of the derivative instrument is recognized in earnings.  Additionally, the change in fair value of the hedged item, attributable to the hedged risk, is recognized as a basis adjustment to the hedged item and is also recognized in earnings.  See Note 6 for further discussion.
Equity Compensation

Equity Compensation

 

See Note 10 for information regarding our accounting for equity compensation awards.
Net Income Per Limited Partner Unit

Net Income Per Limited Partner Unit

 

Basic and diluted net income per unit is determined by dividing our limited partners’ interest in net income attributable to Plains by the weighted average number of limited partner units outstanding during the period.  Pursuant to FASB guidance regarding the application of the two-class method for MLPs, the limited partners’ interest in net income attributable to Plains is calculated by first reducing net income attributable to Plains by the distribution pertaining to the current period’s net income (including the incentive distribution interest in excess of the 2% general partner interest).  Then, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement.

 

The following table sets forth the computation of basic and diluted earnings per limited partner unit for the years ended 2011, 2010 and 2009:

 

 

 

Year Ended December 31,

 

 

 

2011

 

2010

 

2009

 

Numerator for basic and diluted earnings per limited partner unit:

 

 

 

 

 

 

 

Net income attributable to Plains

 

$

966

 

$

505

 

$

579

 

Less: General partner’s incentive distribution (1)

 

(221

)

(168

)

(136

)

Less: General partner 2% ownership

 

(15

)

(7

)

(9

)

Net income available to limited partners in accordance with the application of the two-class method for MLPs

 

$

730

 

$

330

 

$

434

 

 

 

 

 

 

 

 

 

Denominator:

 

 

 

 

 

 

 

Basic weighted average number of limited partner units outstanding

 

149

 

137

 

130

 

Effect of dilutive securities:

 

 

 

 

 

 

 

Weighted average LTIP units (2)

 

1

 

1

 

1

 

Diluted weighted average number of limited partner units outstanding

 

150

 

138

 

131

 

 

 

 

 

 

 

 

 

Basic net income per limited partner unit

 

$

4.91

 

$

2.41

 

$

3.34

 

 

 

 

 

 

 

 

 

Diluted net income per limited partner unit

 

$

4.88

 

$

2.40

 

$

3.32

 

 

(1)                                     We calculate net income available to limited partners based on the distributions pertaining to the current period’s net income.  After adjusting for the appropriate period’s distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the general partner and limited partners in accordance with the contractual terms of the partnership agreement.

 

(2)                                     Our LTIP awards (described in Note 10) that contemplate the issuance of common units are considered dilutive unless (i) vesting occurs only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. LTIP awards that are deemed to be dilutive are reduced by a hypothetical unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB.
Acquisitions and Dispositions
The following acquisitions were accounted for using the purchase method of accounting and the purchase price was determined in accordance with such method.
Legal Contingencies

In the ordinary course of business, we are involved in various legal proceedings. To the extent we are able to assess the likelihood of a negative outcome for these proceedings, our assessments of such likelihood range from remote to probable. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, we accrue the estimated amount. We do not believe that the outcome of these legal proceedings, individually or in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows. Although we believe that our operations are presently in material compliance with applicable requirements, as we acquire and incorporate additional assets it is possible that the Environmental Protection Agency (“EPA”) or other governmental entities may seek to impose fines, penalties or performance obligations on us (or on a portion of our operations) as a result of any past noncompliance whether such noncompliance initially developed before or after our acquisition.