Note 2 — Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements and related notes include our assets, liabilities and results of operations for each of the periods presented. All intercompany accounts and transactions are eliminated in our consolidated financial statements. As of December 31, 2011, we changed our presentation for other current liabilities on our consolidated balance sheet to present separately accrued capital expenditures.

Our management believes that the disclosures in these audited consolidated financial statements are adequate to make the information presented not misleading. In the preparation of these financial statements, we evaluated subsequent events through the issuance date of the financial statements.

Investments in Unconsolidated Affiliates

Although we are the managing partner or member in each of our equity investments and own a majority interest in some of our equity investments, we account for our investments in unconsolidated affiliates using the equity method of accounting. Equity in earnings (loss) from our unconsolidated affiliates is included in income from operations as the operations of each of our unconsolidated affiliates are integral to our operations. We serve each of our equity method investments as operator, managing member or both, but we do not control any of them. Our ability to make certain substantive business decisions with respect to each is subject to the majority or unanimous approval of the owners or management committee. See Note 4.

Use of Estimates

In preparing the financial statements in conformity with accounting policies generally accepted in the United States of America ("GAAP"), management must make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Although our management believes the estimates are appropriate, actual results can differ materially from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include all highly liquid cash investments with original maturities of three months or less when purchased.

Concentration and Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents, accounts receivable and risk management assets and liabilities.

We place our cash and cash equivalents with large financial institutions. We derive our revenue from customers primarily in the natural gas, utility and petrochemical industries. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. Our portfolio of accounts receivable consists primarily of mid-size to large domestic corporate entities. Counterparties that individually accounted for 5% or more of our 2012 revenue collectively accounted for approximately 62% of our 2012 revenue. As of December 31, 2012, all of these companies or their respective parent companies were rated investment grade by Moody's Investors Service and Standard & Poor's Ratings Services, except for Formosa Hydrocarbons Company. Formosa Hydrocarbons Company's parent, Formosa Plastics Corporation, U.S.A., is affiliated with the Taiwan-based Formosa Plastics Group, which is rated investment grade by Standard & Poor's Ratings Services. Companies accounting for another approximately 25% of our revenue have an investment grade parent, are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.

We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review the credit ratings of our hedging counterparties on a monthly basis. As of December 31, 2012, our five largest hedging counterparties accounted for approximately 69% of the value of our net commodity hedging positions and all counterparties were rated Baa1 and A- or better by Moody's Investors Service and Standard & Poor's Ratings Services, respectively.

Allowance for Doubtful Accounts

We extend credit to customers and other parties in the normal course of business. Estimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the level of established reserves, we make judgments regarding economic conditions, each party's ability to make required payments and other factors. As the financial condition of any party changes, other circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. We have established various procedures to manage our credit exposure, including initial credit approvals, credit limits and rights of offset. We also manage our credit risk using prepayments and guarantees to ensure that our management's established credit criteria are met. The activity in the allowance for doubtful accounts is as follows (in thousands):

	Balance at Beginning of Period		Charged to Expense		Write-Offs, Net of Recoveries			Balance at End of Period

Year ended December 31, 2012	$	927	$	115	$	(915	)	$	127
Year ended December 31, 2011		172		808		(53	)		927
Year ended December 31, 2010		211		65		(104	)		172

Property, Plant and Equipment

Our property, plant and equipment consist of intrastate gas transmission systems, gas gathering systems, gas processing, fractionation and treating facilities and other related facilities, and are carried at cost less accumulated depreciation.

	December 31,

	2012			2011
	(In thousands)
Property, plant and equipment, at cost
Pipelines and equipment	$	1,000,831		$	953,401
Gas processing plants and equipment		385,892			345,547
Construction in progress		294,691			70,395
Office furniture and equipment		15,980			12,723

		1,697,394			1,382,066
Less accumulated depreciation, amortization and impairment		(324,885	)		(278,367	)

Property, plant and equipment, net	$	1,372,509		$	1,103,699

We charge repairs and maintenance against income when incurred and capitalize renewals and betterments, which extend the useful life or expand the capacity of the assets. We calculate depreciation on the straight-line method based on the estimated useful lives of our assets as follows:

		Useful Lives

Pipelines and equipment		3-30 years
Gas processing plants and equipment		5-30 years
Other property and equipment		3-10 years

Depreciation expense for the years ended December 31, 2012, 2011 and 2010 was $65,108,000, $60,779,000 and $51,382,000, respectively.

We capitalize interest on major projects during extended construction time periods. Such interest is allocated to property, plant and equipment and amortized over the estimated useful lives of the related assets. We capitalized $11,977,000, $9,675,000 and $3,355,000 of interest related to major projects during the years ended December 31, 2012, 2011 and 2010, respectively.

Intangible Assets

Our intangible assets consist of rights-of-way, easements, contracts and acquired customer relationships. Intangible assets consisted of the following:

	December 31, 2012

	Weighted Average Remaining Amortization Period		Gross Carrying Amount		Accumulated Amortization			Net
	(in years)		(In thousands)
Rights-of-way and easements		19	$	154,849	$	(34,490	)	$	120,359
Contracts		9		68,717		(29,940	)		38,777
Customer relationships		10		4,864		(1,929	)		2,935

Total		16	$	228,430	$	(66,359	)	$	162,071

	December 31, 2011

	Weighted Average Remaining Amortization Period		Gross Carrying Amount		Accumulated Amortization			Net
	(in years)		(In thousands)
Rights-of-way and easements		19	$	145,598	$	(28,822	)	$	116,776
Contracts		17		108,416		(36,014	)		72,402
Customer relationships		11		4,864		(1,617	)		3,247

Total		18	$	258,878	$	(66,453	)	$	192,425

We amortize existing intangible assets and any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable. Initial costs of acquiring new intangible assets are amortized over the estimated useful life of the related tangible assets. Any related renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method.

During 2012, we acquired approximately $646,000 of rights-of-way with a weighted average renewal period of 5 years. These rights-of-way are being amortized over their estimated life of 20 years, which is based on our historical experience of having the ability to renew the agreements as well as our intended use of the asset. However, in order to utilize these rights-of-way over the 20 year-period, we will pay a renewal amount of approximately $891,000 at the end of each 5 year renewal period.

During the three months ended March 31, 2012 and September 30, 2011, we recorded non-cash impairment charges of $28,744,000 and $5,000,000, respectively, with respect to an underutilized contract for firm capacity that we resell to Rocky Mountains producers (see "Other Fair Value Measurements" in Note 9).

Estimated aggregate amortization expense is approximately: 2013 — $11,690,000; 2014 — $11,528,000; 2015 — $11,493,000; 2016 — $11,471,000 and 2017 — $11,228,000.

Impairment of Long-Lived Assets

In accordance with Accounting Standards Codification ("ASC") 360, "Accounting for the Impairment or Disposal of Long-Lived Assets," we evaluate whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management's estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset's carrying value over its fair value, such that the asset's carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the asset, including future commodity prices and estimated future natural gas production in the related region (which is dependent in part on commodity prices). Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

•

changes in general economic conditions in which our assets are located;

•

the availability and prices of natural gas supply;

•

improvements in exploration and production technology;

•

the finding and development cost for producers to exploit reserves in a particular area;

•

our ability to negotiate favorable agreements with producers and customers;

•

our dependence on certain significant customers, producers, gatherers and transporters of natural gas;

•

availability of downstream natural gas and NGL markets; and

•

competition from other midstream service providers, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. See Notes 4 and 9.

Goodwill

Goodwill acquired in a business combination is not subject to amortization. As required by ASC 350, "Intangibles — Goodwill and Other," we test such goodwill for impairment at the reporting unit level on an annual basis and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. For the years ended December 31, 2012, 2011 and 2010, we did not record a goodwill impairment. Goodwill of $518,000 related to our acquisition of Cimmarron Gathering, LP in 2007 is included in other assets as of December 31, 2012 and 2011.

Other Assets

Other assets primarily consist of costs associated with debt issuance costs net of related accumulated amortization. Amortization of other assets is calculated using a method that approximates the effective interest method over the maturity of the associated debt or the term of the associated contract.

Transportation and Exchange Imbalances

In the course of transporting natural gas and NGLs for others, we may receive for redelivery different quantities of natural gas or NGLs than the quantities we ultimately redeliver. These differences are recorded as transportation and exchange imbalance receivables or payables that are recovered or repaid through the receipt or delivery of natural gas or NGLs in future periods, if not subject to cash-out provisions. Imbalance receivables are included in accounts receivable, and imbalance payables are included in accounts payable on the consolidated balance sheets at current market prices in effect for the reporting period of the outstanding imbalances. As of December 31, 2012 and 2011, we had imbalance receivables totaling $585,000 and $566,000, respectively, and imbalance payables totaling $505,000 and $370,000, respectively. Changes in market value and the settlement of any such imbalance at a price greater than or less than the recorded imbalance results in an upward or downward adjustment, as appropriate, to the cost of natural gas sold.

Asset Retirement Obligations

Asset retirement obligations ("AROs") are legal obligations associated with the retirement of tangible long-lived assets that result generally from the acquisition, construction, development or normal operation of the asset. When an ARO is incurred, we recognize a liability for the fair value of the ARO and increase the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value and recognized as accretion expense each period, and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. Upon settlement of the liability, we either settle the obligation for its recorded amount or incur a gain or loss on settlement. We have recorded AROs related to (i) rights-of-way and easements over property we do not own and (ii) regulatory requirements where a legal or contractual obligation exists upon abandonment of the related facility.

The following table presents information regarding our AROs (in thousands):


ARO liability balance, December 31, 2010	$	842
AROs incurred in 2011		161
Accretion for conditional obligations		65

ARO liability balance, December 31, 2011		1,068
ARO incurred in 2012		2
Accretion for conditional obligations		66
ARO settled/released in 2012		(209	)

ARO liability balance, December 31, 2012	$	927

At December 31, 2012 and 2011, there were no assets legally restricted for purposes of settling AROs.

Revenue Recognition

Using the revenue recognition criteria of evidence of an arrangement, delivery of a product and the determination of price, our natural gas and NGL revenue is recognized in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue including processing under firm capacity arrangements. In addition, collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position and their ability to pay.

Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements that establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location on the same or on another specified date. All transactions require physical delivery of the natural gas, and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

On occasion, we enter into buy/sell arrangements that are accounted for on a net basis in the statements of operations as either a net natural gas sale or a net cost of natural gas, as appropriate. These purchase and sale transactions are generally detailed either jointly, in a single contract or separately, in individual contracts that are entered into concurrently or in contemplation of one another with a single or multiple counterparties.

Our contract mix reflects a variety of pricing terms typical for the midstream industry, with varying levels of commodity price sensitivity, including fee-based, percent-of-proceeds, percent-of-index and keep-whole terms. In addition to compensating us for gathering, transportation, processing, or fractionation services, many of our contracts also allow us to charge fees for treating, compression, dehydration, nitrogen rejection or other services. Generally:

•

our margins from fee-based pricing are directly related to the volumes of natural gas or NGLs that flow through our systems and are not directly affected by commodity prices;

•

our margins from percent-of-proceeds (including percent-of-liquids) pricing and percent-of-index pricing for lean gas that does not require processing are generally directly related to the prices for natural gas, NGLs or both; in other words, our margins increase or decrease as prices increase or decrease; and

•

our margins from keep-whole pricing and percent-of-index pricing involving gas that we process are related not only to natural gas and NGL prices but also to the spread between natural gas and NGL prices. As NGL prices increase relative to natural gas prices, our margins increase, and if NGL prices decrease relative to natural gas prices, our margins decrease. Our keep-whole contracts include terms that help us avoid incurring losses that would result if NGL prices fell near or below natural gas prices, such as allowing us to charge fees and reduce the volume of NGLs we recover during unfavorable pricing environments. Also, to the extent our contract entitles us to keep extracted NGLs, we may share a portion of our processing margin with the counterparty when processing margins are favorable.

In addition, some of our fee-based and percent-of-proceeds contracts include "fixed recovery" provisions, which operate in conjunction with the contract's main pricing terms. Under fixed recovery terms, we determine the amount payable, or the volumes of residue gas and NGLs deliverable, to the counterparty based on contractual NGL recovery factors. Fixed recovery terms can affect our margins to the extent that our actual recoveries vary from the agreed NGL recovery factor. If we exceed fixed recoveries when processing margins are favorable, our margins will benefit to the extent of the difference. However, our margins will decrease to the extent we do not meet the NGL recovery factor in a favorable processing margin environment, and we could incur losses. If NGL prices are unfavorable relative to natural gas prices, we would be able to increase our margins by reducing our recoveries.

Risk Management Activities

We engage in risk management activities that take the form of derivative instruments to manage the risks associated with natural gas and NGL prices and the fluctuation in interest rates. Through our risk management activities, we must estimate the fair value of our financial derivatives using valuation models based on whether the inputs to those valuation techniques are observable or unobservable.

ASC 815, "Derivatives and Hedging," as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. In accordance with ASC 815, we recognize all derivatives as either risk management assets or liabilities in our consolidated balance sheets and measure those instruments at fair value. Changes in the fair value of financial instruments over time are recognized into earnings unless specific hedging criteria are met. If the financial instruments meet the hedging criteria, changes in fair value will be recognized in earnings for fair value hedges and in other comprehensive income for the effective portion of cash flow hedges. Ineffectiveness in cash flow hedges is recognized in earnings in the period in which the ineffectiveness occurs. Gains and losses on cash flow hedges are reclassified to operating revenue as the forecasted transactions impact earnings. We included changes in our risk management activities in cash flow from operating activities on the consolidated statements of cash flows.

ASC 815 does not apply to non-derivative contracts or derivative contracts that are subject to a normal purchases and normal sales exclusion. Contracts for normal purchases and normal sales provide for the purchase or sale of something other than a financial instrument or derivative instrument and for delivery in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business. Our forward natural gas purchase and sales contracts are either not considered a derivative or are subject to the normal purchases and normal sales scope exception. These contracts generally have terms ranging between one and five years, although a small number continue for the life of the dedicated production.

We use financial instruments such as puts, calls, swaps and other derivatives to mitigate the risks to our cash flow and profitability resulting from changes in commodity prices and interest rates. We recognize these transactions as assets and liabilities on our consolidated balance sheets based on the instrument's fair value. Our financial instruments have been designated and accounted for as cash flow hedges except as discussed in Note 9.

We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of ASC 820, "Fair Value Measurement," as discussed in Note 9.

Interest and Other Financing Costs

Interest and other financing costs includes interest and fees incurred and amortization of debt issuance costs related to our senior secured revolving credit facility and senior unsecured notes discussed in Note 5, net cash settlements of interest rate swaps, net unrealized mark-to-market gain or loss on interest rate swaps, capitalized interest and non-cash ineffectiveness of interest rate swaps.

Income Taxes

Three of our 100% owned subsidiaries, Copano General Partners, Inc. ("CGP") and Copano Energy Finance Corporation ("CEFC"), both Delaware corporations, and CPNO Services, L.P. ("CPNO Services"), a Texas limited partnership, are the only entities within our consolidated group subject to federal income taxes. CGP's operations primarily include its indirect ownership of the managing general partner interest in certain of our Texas operating entities. CEFC was formed in July 2005 and is a co-issuer of our senior unsecured notes discussed in Note 5. CPNO Services allocates administrative and operating costs, including payroll and benefits expenses, to us and certain of our operating subsidiaries. As of December 31, 2012, CGP and CPNO Services have estimated a combined net operating loss ("NOL") carry forward of approximately $6,916,000, for which a valuation allowance has been recorded. Our NOL carry forwards have a 20 year life and expire between 2025 and 2032. We recognized no significant income tax expense for the years ended December 31, 2012, 2011 and 2010. Except for income allocated with respect to CGP, CEFC and CPNO Services, our income is taxable directly to our unitholders.

We do not provide for federal income taxes in the accompanying consolidated financial statements, as we are not subject to entity-level federal income tax. However, we are subject to the Texas margin tax, which is imposed at a maximum effective rate of 0.7% on our annual "margin," as defined in the Texas margin tax statute enacted in 2007. Our annual margin generally is calculated as our revenues for federal income tax purposes less the "cost of the products sold" as defined in the statute. The provision for the Texas margin tax totaled $1,654,000, $1,453,000 and $895,000 for the years ended December 31, 2012, 2011 and 2010, respectively. Under the provisions of ASC 740, "Accounting for Income Taxes," we are required to record the effects on deferred taxes for a change in tax rates or tax law in the period that includes the enactment date. Under ASC 740, taxes based on income, like the Texas margin tax, are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The deferred tax provisions presented on the accompanying consolidated balance sheets relate to the effect of temporary book/tax timing differences associated with depreciation.

Net Income Per Unit

Net income (loss) per unit is calculated in accordance with ASC 260, "Earnings Per Share," which specifies the use of the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed.

Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class during the period. Dilutive net income (loss) per unit reflects potential dilution that could occur if convertible securities were converted into common units or contracts to issue common units were exercised except when the assumed conversion or exercise would have an anti-dilutive effect on net income (loss) per unit. Dilutive net income (loss) per unit is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class of units during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been issued.

Because we had a net loss to common units for the years ended December 31, 2012, 2011 and 2010, the weighted average units outstanding are the same for basic and diluted net loss per common unit. The following potentially dilutive common equity was excluded from the dilutive net loss per unit calculation because to include these equity securities would have been anti-dilutive.

	Year Ended December 31,

	2012		2011		2010
	(In thousands)
Options		637		766		962
Unit appreciation rights		477		407		360
Restricted units		43		44		60
Phantom units		1,172		997		882
Contingent incentive plan unit awards		—		100		64
Series A preferred units		12,897		11,684		10,585

Equity-Based Compensation

We account for equity-based compensation expense in accordance with ASC 718, "Stock Compensation." We estimate grant date fair value using either an option-pricing model that is consistent with the terms of the award or a market observed price, if such a price exists. This cost is recognized over the period during which an employee is required to provide services in exchange for the award (which is usually the vesting period). We treat equity awards granted as a single award and recognize equity-based compensation expense on a straight-line basis (net of estimated forfeitures) over the employee service or vesting period. Equity-based compensation expense is recorded in operations and maintenance expenses and general and administrative expenses in our consolidated statements of operations. See Note 6.

401(k) Plan

We sponsor a 401(k) tax deferred savings plan, whereby we match a portion of employees' contributions in cash. Participation in the plan is voluntary and all employees who are 21 years of age are eligible to participate. For the year ended December 31, 2010, we suspended our contribution match program as a result of the economic downturn and business environment. In 2011, we reinstated our discretionary contribution match and matched employee contributions dollar-for-dollar on the first 3% of an employee's pretax earnings. For 2012, we matched employee contributions dollar-for-dollar on the first 3% and $0.50 per dollar for the next 2% of an employee's pretax earnings. We charged to expense plan contributions of $1,094,000 and $444,000 in 2012 and 2011, respectively.