Gibson Energy ULC 6-K 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Exhibit 99.1

Gibson Energy ULC

Quarterly Report

For the Three Month Period Ended March 31, 2011

1. Financial Statements

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

1. Financial Statements

Gibson Energy Holding ULC

Condensed Consolidated Balance Sheet

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	March 31, 2011			December 31, 2010			January 1, 2010
Assets
Current assets
Cash and cash equivalents	$	51,989		$	7,225		$	26,263
Trade and other receivables	405,777			354,682			315,865
Income taxes receivable	57,130			57,130			15,541
Inventories (note 5)	158,157			197,483			113,688
Prepaid expenses and other assets	9,214			7,843			4,045
Net investment in finance leases (note 6)	236			236			—
Assets held for sale	—			33,596			—
Total current assets	682,503			658,195			475,402
Non-current assets
Deferred income tax assets	17,024			13,422			6,734
Long-term prepaid expenses and other assets	21,826			21,990			29,032
Net investment in finance leases (note 6)	20,206			20,265			—
Property, plant and equipment (note 7)	633,539			629,755			570,307
Intangible assets	145,122			152,339			121,909
Goodwill	495,157			496,416			433,894
Total non-current assets	1,332,874			1,334,187			1,161,876
Total assets	$	2,015,377		$	1,992,382		$	1,637,278
Liabilities
Current liabilities
Credit Facility (note 8)	$	—		$	43,500		$	25,000
Trade payables and accrued charges	418,404			393,686			254,869
Deferred revenue	63,985			54,701			13,405
Income taxes payable	1,583			1,217			8,443
Liabilities related to assets held for sale	—			3,762			—
Total current liabilities	483,972			496,866			301,717
Non-current liabilities
Long-term debt (note 9)	702,651			718,154			553,942
Provisions (note10)	43,172			43,251			40,623
Other long-term liabilities (note11)	6,634			6,445			5,895
Deferred income tax liabilities	196,887			182,858			190,523
Total non-current liabilities	949,344			950,708			790,983
Total liabilities	1,433,316			1,447,574			1,092,700
Equity
Share capital	668,827			664,724			650,690
Contributed surplus	14,207			13,586			8,957
Accumulated other comprehensive loss	(10,841		)	(7,342		)	—
Deficit	(90,132		)	(126,160		)	(115,069		)
Total equity	582,061			544,808			544,578
Total liabilities and shareholder’s equity	$	2,015,377		$	1,992,382		$	1,637,278
Commitments and contingencies (note12)

See accompanying notes

1

Gibson Energy Holding ULC

Condensed Consolidated Statement of Income

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	Three months ended March 31
	2011			2010
Revenue (note 13)	$	1,148,017		$	964,529
Cost of sales (note 14, 15 and 20)	1,104,199			938,252
Gross profit	43,818			26,277
General and administrative (note 14 and 15)	7,374			8,070
Gain on sale of Edmonton North Terminal (note 7)	(20,370		)	—
Other operating expenses (note 16)	1,176			535
Income from operating activities	55,638			17,672
Loss from investment in associates	86			504
Interest expense (note 20)	24,705			24,036
Interest income	(58		)	(216		)
Foreign exchange gain on long-term debt (note 9)	(17,328		)	(20,800		)
Income before income taxes	48,233			14,148
Income tax provision (note 17)	8,102			3,167
Net income	$	40,131		$	10,981

See accompanying notes

2

Gibson Energy Holding ULC

Condensed Consolidated Statement of Comprehensive Income

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	Three months ended March 31
	2011			2010
Net income	$	40,131		$	10,981
Other comprehensive income (loss)
Cumulative translation adjustment, net of tax	(3,499		)	—
Other comprehensive income (loss)	(3,499		)	—
Comprehensive income	$	36,632		$	10,981

See accompanying notes

3

Gibson Energy Holding ULC

Condensed Consolidated Statement of Changes in Equity

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	Share capital		Contributed surplus		Accumulated other comprehensive income (loss)			Deficit			TotalEquity
Balance — January 1, 2011	$	664,724	$	13,586	$	(7,342	)	$	(126,160	)	$	544,808
Net income	—		—		—			40,131			40,131
Other comprehensive income, net of tax:
Cumulative translation adjustment	—		—		(3,499		)	—			(3,499		)
Employee share options:
Value of services recognized	—		621		—			—			621
Dividends	4,103		—		—			(4,103		)	—
Balance — March 31, 2011	$	668,827	$	14,207	$	(10,841	)	$	(90,132	)	$	582,061
Balance — January 1, 2010	$	650,690	$	8,957	$	—		$	(115,069	)	$	544,578
Net income	—		—		—			10,981			10,981
Employee share options:
Value of services recognized	—		1,150		—			—			1,150
Dividends	3,371		—		—			(3,371		)	—
Balance — March 31, 2010	$	654,061	$	10,107	$	—		$	(107,459	)	$	556,709

See accompanying notes

4

Gibson Energy Holding ULC

Condensed Consolidated Statement of Cash Flows

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	Three months ended March 31
	2011			2010
Cash provided by (used in)
Operating activities
Income from operating activities	$	55,638		$	17,672
Items not affecting cash
Depreciation of property, plant and equipment (note 14)	16,067			12,958
Amortization of intangible assets (note 14)	7,739			5,717
Stock based compensation	621			1,150
Loss (gain) on disposal of assets	(20,468		)	4
Other	(585		)	1,185
Net (gain) loss on fair value movement of financial instruments	(3,034		)	696
Changes in items of working capital
Trade and other receivables	(61,135		)	(1,640		)
Inventories	39,263			(9,237		)
Other current assets	(1,480		)	97
Trade payables and accrued charges	21,727			16,386
Deferred revenue	9,284			(1,501		)
Income taxes paid (note 12)	(66		)	(20,106		)
Net cash provided by operating activities	63,571			23,381
Investing activities
Purchase of property, plant and equipment	(16,874		)	(7,162		)
Purchase of intangible assets	(1,515		)	(639		)
Proceeds on disposal of assets	54,495			140
Acquisitions, net of cash acquired (note 4)	—			(22,720		)
Net cash provided by (used in) investing activities	36,106			(30,381		)
Financing activities
Proceeds from long-term debt, net of debt discount (note 9)	—			200,888
Payment of debt issue costs	—			(6,544		)
Proceeds from Credit Facility (note 8)	109,000			—
Repayment of Credit Facility (note 8)	(152,500		)	(25,000		)
Interest received	58			216
Interest paid	(10,884		)	(1,972		)
Net cash provided by (used in) financing activities	(54,326		)	167,588
Effect of exchange rate on cash and cash equivalents	(587		)	(1,309		)
Net increase in cash and cash equivalents	44,764			159,279
Cash and cash equivalents — beginning of period	7,225			26,263
Cash and cash equivalents — end of period	$	51,989		$	185,542

See accompanying notes

5

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

1General Information

Gibson Energy Holding ULC and its subsidiaries (together the “Company” or “Gibson”) is engaged in the movement, storage, blending, processing and marketing and distribution of crude oil, condensate, natural gas liquids and refined products. The Company is incorporated and domiciled in Canada. The address of its registered office is 1700, 440 Second Avenue SW., Calgary, Alberta, Canada.

The Company is a wholly owned subsidiary of R/C Guitar Cooperative of U.A., a Dutch co-op owned by investment funds affiliated with Riverstone Holding LLC (“Riverstone”).

2Basis of preparation and adoption of IFRS

The Company prepares its financial statements in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) as set out in the Handbook of the Canadian Institute of Chartered Accountants (“CICA Handbook”). In 2010, the CICA Handbook was revised to incorporate International Financial Reporting Standards (“IFRS”), and requires publicly accountable enterprises to apply such standards effective for years beginning on or after January 1, 2011. Accordingly, the Company has commenced reporting on this basis in these condensed consolidated interim financial statements.

These condensed consolidated interim financial statements have been prepared in accordance with IFRS applicable to the preparation of interim financial statements, including IAS 34 and IFRS 1. The Company has consistently applied the same accounting policies in its opening IFRS balance sheet at January 1, 2010 and throughout all periods presented, as if these policies had always been in effect. Note 22 discloses the impact of the transition to IFRS on the Company’s reported financial position, financial performance and cash flows, including the nature and effect of significant changes in accounting policies from those used in the Company’s consolidated financial statements for the year ended December 31, 2010.

The policies applied in these condensed consolidated interim financial statements are based on IFRS issued and outstanding as of May 12, 2011, the date the Board of Directors approved the statements. Any subsequent changes to IFRS, that are given effect in the Company’s annual consolidated financial statements for the year ending December 31, 2011, could result in restatement of these interim consolidated financial statements, including the transition adjustments recognized on change-over to IFRS.

These condensed consolidated interim financial statements should be read in conjunction with the Company’s Canadian GAAP annual consolidated financial statements for the year ended December 31, 2010. Note 23 discloses IFRS information for the year ended December 31, 2010 that is material to understand these condensed consolidated interim financial statements.

The Company’s condensed consolidated interim financial statements are presented in Canadian dollars, the Company’s functional currency, and all values are rounded to the nearest thousands of dollars, except where indicated otherwise.  All references to $ are to Canadian dollars and references to U.S.$ are to U.S. dollars.

6

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

3Significant accounting policies

Basis of measurement

The consolidated financial statements have been prepared under the historical cost convention, except for the revaluation of certain financial assets and financial liabilities to fair value, including financial instruments.

Basis of consolidation

The consolidated financial statements include the results of the Company and its subsidiaries. Subsidiaries are all entities over which the Company has the power to govern the financial and operating policies.  Subsidiaries are fully consolidated from the date on which control is transferred to the Company and continue to be consolidated until the date control ceases.  All intercompany transactions, balances, income and expenses are eliminated on consolidation.

Investments in unincorporated joint ventures are accounted for using the proportionate consolidation method, whereby the Company’s share of revenues, expenses, assets and liabilities are included in the accounts.

Investments in associates

An associate is an entity over which the Company has significant influence and that is neither a subsidiary nor an interest in a joint venture. Generally, the Company regards an investment of between 20% and 50% as an associate. The financial results of the Company’s investments in associates are included in the Company’s results according to the equity method of accounting. Subsequent to the acquisition date, the Company’s share of profits or losses of associates is recognized in the statement of income and its share of other comprehensive income (loss) of associates is included in other comprehensive income (loss).

The Company assesses at each year end whether there is any objective evidence that its interests in associates are impaired. If impaired, the carrying value is written down to its estimated recoverable amount and charged to the statement of income.

Foreign currency translation

The financial statements for each of the Company’s subsidiaries and associates are prepared using their functional currency. The functional currency is the currency of the primary economic environment in which an entity operates.  The presentation and functional currency of the Company is Canadian dollars.  Assets and liabilities of foreign operations are translated into Canadian dollars at the market rates existing at the balance sheet date. Operating results are translated at the average rates for the period. Exchange differences arising on the consolidation of the net assets of foreign operations are recorded in other comprehensive income (loss). On January 1, 2010, the Company did not have material foreign operations, and therefore the cumulative translation difference on January 1, 2010 was zero.

Foreign currency transactions are translated into the functional currency using exchange rates prevailing at the transaction date. Generally, foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at period end exchange rates of monetary assets and liabilities denominated in currencies other than an entity’s functional currency are recognized in the statement of income.

7

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Business combinations and goodwill

Business combinations are accounted for using the purchase method of accounting. The cost of an acquisition is measured as the cash paid and the fair value of other assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Direct costs incurred by the Company in connection with an acquisition, such as finder’s fees, advisors, legal, accounting, valuation and other professional or consulting fees, are expensed as incurred. The acquired identifiable assets, liabilities and contingent liabilities are measured at their fair values at the date of acquisition. Any excess of the cost of acquisition over the net fair value of the identifiable assets, liabilities and contingent liabilities acquired is recognized as goodwill. Any deficiency of the cost of acquisition below the fair values of the identifiable net assets acquired (i.e. discount on acquisition) is credited to the statement of income in the period of acquisition.

At the acquisition date, any goodwill acquired is allocated to each of the operating segments expected to benefit from the combination’s synergies. For this purpose, cash-generating units are set at one level below an operating segment. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses.

Intangible assets

An intangible asset acquired as part of a business combination is measured at fair value at the date of acquisition and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights and its fair value can be measured reliably. Intangible assets acquired separately from a business are carried initially at cost. The initial cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

Intangible assets with a finite life are amortized on a straight-line basis over their expected useful lives. Amortization rates are as follows:

Brands	10 years
Customer relationships	4 – 12 years
Long-term customer contracts	6 – 10 years
Non-compete agreements	2 – 10 years
Technology	3 – 5 years
Software	3 – 7 years

The expected useful lives of intangible assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

Property, plant and equipment

Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of any decommissioning obligation, if any, and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset. Expenditures on major maintenance refits or repairs are comprised of the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the Company, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated with major maintenance

8

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

programmes are capitalized and amortized over the period to the next inspection. All other maintenance costs are expensed as incurred.

Depreciation is charged so as to write off the cost of assets, other than assets under construction, using the straight-line method over their expected useful life.

The useful lives of the Company’s property, plant and equipment are as follows:

Buildings	10 - 20 years
Pipelines	8 - 20 years
Tanks	20 - 33 years
Equipment	3 - 20 years
Rolling stock	10 - 23 years
Plant and Equipment	3 - 25 years

The expected useful lives of property, plant and equipment, residual values and methods of amortization are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in the statement of income in the period the item is derecognized.

Impairments

The Company carries out impairment reviews in respect of goodwill at least annually or if indicators of impairment exist. The Company also assesses at least annually whether there have been any events or changes in circumstances that indicate that property, plant and equipment, inventories and other intangible assets may be impaired and an impairment review is carried out whenever such an assessment indicates that the carrying amount may not be recoverable. Such indicators include changes in the Company’s business plans, changes in activity levels, an increase in the discount rate and evidence of physical damage.  For the purposes of impairment testing, assets are grouped at the lowest levels for which there are separately identifiable cash flows.  Where impairment exists, the asset is written down to its recoverable amount, which is the higher of the fair value less costs to sell and value in use. Impairments are recognized immediately in the statement of income.

The assessment for impairment entails comparing the carrying value of the asset or cash-generating unit with its recoverable amount, that is, the higher of fair value less costs to sell and value in use. Value in use is usually determined on the basis of discounted estimated future net cash flows. However, the determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as the outlook for global or regional market supply-and-demand conditions, future commodity prices, the effects of inflation on operating expenses and discount rates.

An impairment loss in respect of goodwill is not reversed. In respect of other assets, an impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount that causes the asset’s recoverable amount to exceed the asset’s carrying amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been previously recognized.

9

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Inventories

Crude oil, diluent, natural gas liquids, natural gas, road asphalt, roofing flux, wellsite fluids, distillate and spare parts are carried at the lower of average cost and net realizable value, with cost determined using a weighted average cost method. Net realizable value is the estimated selling price less applicable selling expenses.

Financial assets

Financial assets include cash and cash equivalents, trade receivables, other receivables and other investments. The Company determines the classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value, normally being the transaction price plus directly attributable transaction costs.

Cash and cash equivalents

Cash and cash equivalents comprise cash on hand and current balances with banks and similar institutions which are readily convertible to cash. These are classified as “loans and receivables” with gains or losses recognized through statement of comprehensive income. Cash equivalents are short term deposits with an original maturity of 90 days or less.

Loans and receivables

Loans and receivables are non- financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when the loans and receivables are derecognized or impaired, as well as through the amortization process. This category of financial assets includes trade and other receivables.

A provision for impairment of trade receivables is established when there is objective evidence that the Company will not be able to collect all amounts due according to the original terms of the receivables. Significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganization, and default or delinquency in payments (more than 60 days overdue) are considered indicators that the trade receivable may be impaired. The amount of the provision is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate. The carrying amount of the asset is reduced through the use of an allowance account, and the amount of the loss is recognized in the statement of income. When a trade receivable is determined to be uncollectible, it is written off against the allowance account for trade receivables.

Financial liabilities

Financial liabilities include trade payables, accruals, Credit Facility and long-term debt. The group determines the classification of its financial liabilities at initial recognition. All financial liabilities are initially recognized at fair value. For interest-bearing loans and borrowings this is the fair value of the proceeds received net of issue costs associated with the borrowing. After initial recognition, financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs, and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized respectively in interest and other revenues and finance costs. This category of financial liabilities includes trade and other payables and finance debt.

10

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Leases - lessee

All of the leases where the Company is the lessee are operating leases, and payments under these leases are charged to the statement of income as incurred over the life of the lease.

Leases - lessor

Contractual arrangements that transfer substantially all the risks and benefits of ownership of property to the lessee and, at the inception of the lease, the fair value of the leased property is equal to the Company’s carrying amount of the property are recorded as a net investment in a finance lease.  The minimum lease payments under such arrangements are recorded at the inception of the arrangement and the finance income is recognized in a manner that produces a consistent rate of return on the investment in the finance lease and is included in revenue.

Operating lease income is recognized in the statement of income as it is earned.

Financial instruments

Financial instruments are used by the Company to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and certain operating costs.

The Company periodically enters into crude oil futures, swaps and option contracts to manage the price risk associated with sales, purchases and inventories of crude oil and petroleum products. The Company also periodically purchases foreign exchange forward contracts and options to manage foreign exchange exposures on sales to customers in the United States and the related accounts receivable and U.S. dollar denominated interest payments.

Financial instruments, used periodically by the Company to manage exposure to market risks relating to commodity prices and foreign currency exchange rates, are not designated as hedges. They are recorded at fair value and recorded on the Company’s balance sheet as either an asset, when the fair value is positive, or a liability, when the fair value is negative. Changes in fair value are recorded in the statement of income. The estimated fair value of all financial instruments is based on quoted market prices, or, in their absence, third party market indications and forecasts. Gains or losses from financial instruments related to commodity prices are recognized in cost of sales.

The Company reflects the fair value of these financial instruments based on valuation information from third parties. The calculation of the fair value of certain of these instruments is based on proprietary models and assumptions of third parties because such instruments are not quoted on an active market. Additionally, estimates of fair value may vary among different models due to a difference in assumptions applied, such as the estimate of prevailing market prices, volatility, correlations and other factors, and may not be reflective of the price at which they can be settled due to the lack of a liquid market. As a result of changes in key assumptions, the actual amounts may vary significantly from estimated amounts.

11

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Provisions and contingencies

Provisions are recognized when the Company has a present obligation, legal or constructive, as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.

If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of time is recognized within interest expense.

Decommissioning

Liabilities for site restoration on the retirement of assets are recognized when the Company has an obligation to restore the site, and when a reliable estimate of that liability can be made. Where an obligation exists for a new facility, this will be recognized on construction. An obligation may also crystallize during the period of operation of a facility through a change in legislation or through a decision to terminate operations. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. Estimated future expenditure is based on all known facts at the time and current expected plans for decommissioning. Among the many uncertainties that may impact the estimates are changes in laws and regulations, public expectations, prices and changes in technology.

A corresponding item of property, plant and equipment of an amount equivalent to the provision is also recorded. This is subsequently depreciated as part of the asset. Other than the unwinding discount on the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding item of property, plant and equipment.

Environmental expenditures and liabilities

Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing of recognition of these provisions coincides with the completion of a feasibility study or a commitment to a formal plan of action. The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure. Estimated future expenditure is based on all known facts at the time and an assessment of the ultimate outcome. A number of factors affect the cost of environmental remediation, including the determination of the extent of contamination, the length of time remediation may require, the complexity of environmental regulations and the advancement of remediation technology.

12

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Employee benefits

Defined benefit pension plans and post retirement benefits

The estimated future cost of providing defined benefit pension and other post-retirement benefits (“OPRB”) is actuarially determined using the projected unit credit method and the Company’s best estimates of demographic and financial assumptions, and such cost is accrued proportionately from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based on a year-end market rate of interest for high-quality debt instruments with cash flows that match the timing and amount of expected benefit payments.

Defined contribution pension plans

The Company’s defined contribution plans are funded as specified in the plans and the pension expense is recorded as the benefits are earned and become payable.

Share-based payments

The fair value of employee stock option plans is measured at the date of grant of the option using the Black-Scholes model. The resulting cost, as adjusted for the expected and actual level of vesting of the options, is expensed over the period in which the options vest. At each balance sheet date before vesting, the cumulative expense is calculated, representing the extent to which the vesting period has expired and an estimate of the number of equity instruments that will ultimately vest.

The movement in the cumulative expense since the previous balance sheet date is recognized in the statement of income with a corresponding adjustment to contributed surplus.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable and it requires the input of highly subjective assumptions. Expected volatility of the Company’s shares is based on comparable companies in the industry because the Company does not have historical volatility data for its own stock. The expected term of options represents the period of time that options granted are expected to be outstanding. The risk-free rate is based on the Government of Canada’s Canadian Bond Yields with a remaining term equal to the expected life of the options used in the Black-Scholes valuation model. In the future, as the Company gains historical data for volatility in its own stock and the actual term over which employees hold its options, expected volatility and expected term may change, which could substantially change the grant-date fair value of future awards of stock options and, ultimately, the expense the Company records.

Termination benefit

The Company recognizes termination benefits when it is demonstrably committed to either terminating the employment of current employees according to a detailed formal plan without possibility of withdrawal, or providing benefits as a result of an offer made to encourage voluntary termination.

13

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Income taxes

Income tax expense represents the sum of the income tax currently payable and deferred income tax. Interest and penalties relating to income tax are also included in income tax expense.

The income tax currently payable is based on the taxable income for the period. Taxable income differs from net income as reported in the statement of income because it excludes items of income or expense that are taxable or deductible in other periods and it further excludes items that are never taxable or deductible. The Company’s liability for current income tax is calculated using income tax rates that have been enacted or substantively enacted by the balance sheet date.

Deferred income tax is provided for using the liability method of accounting. Deferred income tax assets and liabilities are determined based on differences between the financial reporting and income tax basis of assets and liabilities. These differences are then measured using enacted or substantially enacted income tax rates and laws that will be in effect when these differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in income in the period that the change occurs.

The Company is entitled to investment tax credits (‘‘ITCs’’) based on certain research and experimental development costs incurred. Investment tax credits and other cost recoveries related to property, plant and equipment are credited against the book value of property, plant and equipment and the credit is released to income on a straight-line basis as a reduction of amortization expense over the above mentioned estimated useful lives of the relevant assets.

Income tax in interim periods is accrued using the tax rate that would be applicable to expected annual earnings.

The computation of the Company’s income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by the Company can take significant time to complete and in some cases it is difficult to predict the ultimate outcome. In addition, the Company has carry-forward tax losses in certain taxing jurisdictions that are available to offset against future taxable income. However, deferred tax assets are recognized only to the extent that it is probable that taxable income will be available against which the unused tax losses can be utilized. Management judgement is exercised in assessing whether this is the case. To the extent that actual outcomes differ from management’s estimates, income tax charges or credits may arise in future periods.

Revenue recognition

Product revenues associated with the sales of crude oil, diluent, asphalt, natural gas liquids, natural gas, wellsite fluids and distillate owned by the Company are recognized when significant risks and rewards of ownership passes to the customer and physical delivery occurs, the price can be measured reliably and collection is probable. Sales terms are generally FOB shipping point, in which case the sales are recorded at the time of shipment, because this is when title and risk of loss are transferred. All payments received before delivery are recorded as deferred revenue and are recognized as revenue when delivery occurs, assuming all other criteria are met. Freight costs billed to customers are recorded as a component of revenue. Revenues from buy/sell transactions whereby the Company acts as an agent are recorded on a net basis.

Revenue associated with the provision of transportation and terminalling and pipeline services are recognized when the services are provided, the price can be measured reliably and collection is probable. Revenue from non-refundable propane tank fees are recorded in deferred revenue and recognized in revenue on a straight line basis over the rental period, typically one year.

14

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in operating expenses.

Interest

Interest income and expense is recognized in the statement of income using the effective interest rate method. Interest income and expense is classified as a financing activity in the consolidated statement of cash flows.

Borrowing costs

Borrowing costs that arise in connection with the construction of a qualifying asset are capitalized and subsequently amortized in line with the depreciation of the related asset. Borrowing costs are capitalized from the beginning of construction until the point at which the qualifying asset is substantially ready for its intended use. All other borrowing costs are recognized as interest expense in the statement of income in the period incurred.

Debt issue costs

Costs arising on the issue of new loan facilities are deferred and amortized through interest expense using the effective interest rate method.

Share capital

Common and preferred shares are classified as equity. Incremental costs directly attributable to the issuance of shares are recognized as a deduction from equity.

Use of estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as well as the disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting period. Actual outcomes could differ from those estimates.

The significant estimates and assumptions used are in determining the recoverability of the carrying value of goodwill, intangible assets and property, plant and equipment, the useful lives of intangible assets and property, plant and equipment, income taxes, decommissioning obligations, remediation liability and the valuation of stock options. Details of significant estimate and judgements made for these areas are included in the related accounting policies.

15

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Segmental reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker. The chief operating decision maker, who is responsible for resource allocation and assessing performance of the operating segments, has been identified as the President and Chief Executive Officer.

Recent accounting pronouncements

The IASB intends to replace IAS 39, “Financial Instruments: Recognition and Measurements” (“IAS 39”) with IFRS 9, “Financial Instruments” (“IFRS 9”).  IFRS 9 will be published in three phases, of which the first phase has been published.

The first phase addresses the accounting for financial assets and financial liabilities.  The second phase will address the impairment of financial instruments, and the third phase will address hedge accounting.

For financial assets, IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, and replaces the multiple rules in IAS 39.  The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets.  The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39.  For financial liabilities, although the classification criteria for financial liabilities will not change under IFRS 9, the approach to the fair value option for financial liabilities may require different accounting for changes to the fair value of a financial liability as a result of changes to an entity’s own credit risk.

IFRS 9 is effective for annual periods beginning on or after January 1, 2013 with different transitional arrangements depending on the date of initial application.  The Company is currently evaluating the impact of adopting IFRS 9 on our consolidated financial statements.

4Business acquisitions

The following acquisitions relate to acquisitions of companies that operate within the same business segments of the Company and will provide the Company an expanded client base within these industries.

Aarcam Propane & Construction Heat Ltd.

On February 1, 2010, the Company purchased 100 percent of the common shares of Aarcam Propane & Construction Heat Ltd. (“Aarcam”) a propane retailer in Calgary, for cash, net of cash acquired, of $3.4 million. Acquisition costs relating to external legal fees and due diligence costs were not material. This acquisition will further expand the Company’s market presence and provide the Company with an expanded client base. This acquisition was accounted for using the purchase method with the results from operations included in these financial statements from the date of acquisition.

16

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

The net assets acquired have been recorded as follows:

	Fair Value
Property, plant and equipment	$	1,628
Trade receivables	864
Inventory	55
Goodwill (1)	860
Intangible assets (2)	922
Trade payables and accrued charges	(362		)
Future income taxes	(530		)
Net assets acquired	$	3,437

(1)The amount of purchased goodwill is not expected to be deductible for tax purposes.

(2)Consists of non-compete agreement of $0.6 million and customer relationships of $0.3 million.

The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.

The trade receivables are comprised of gross contractual amounts of $0.9 million, none of which were expected to be uncollectible at the acquisition date.

Included in the purchase price is contingent consideration of $0.5 million which represents its fair value at the acquisition date. This consideration is payable if certain earnings targets are met over the next three years.

Johnstone Tank Trucking Ltd.

On January 31, 2010, the Company purchased 100 percent of the common shares of Johnstone Tank Trucking Ltd. (“Johnstone”) for cash, net of cash acquired, of $21.3 million. Acquisition costs relating to external legal fees and due diligence costs were not material. Johnstone Tank Trucking provides fluid hauling, acid hauling, vacuum service and pressure trucking for the oil and gas industry across southern Saskatchewan. This acquisition will further expand the Company’s market presence and provide access to activity related to the Bakken oilfields. This acquisition was accounted for using the purchase method with the results from operations included in these financial statements from the date of acquisition.

The net assets acquired have been recorded as follows:

	Fair Value
Property, plant and equipment	$	7,892
Trade receivables	4,395
Inventory	141
Prepaid expenses	352
Goodwill (1)	6,656
Intangible assets (2)	7,687
Trade payables and accrued charges	(2,638		)
Future income taxes	(3,219		)
Net assets acquired	$	21,266

(1)The amount of purchased goodwill is not expected to be deductible for tax purposes.

(2)Consists of non-compete agreement of $6.0 million and customer relationships of $1.6 million.

17

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.

The trade receivables are comprised of gross contractual amounts of $4.4 million, none of which were expected to be uncollectible at the acquisition date.

Included in the purchase price is contingent consideration of $0.6 million, which represents its fair value at the acquisition date. This consideration is payable if certain earnings targets are met in the year following the acquisition. These targets were met and the amount was paid in full in the three months ended March 31, 2011.

In the three months ended March 31, 2011 and 2010, the acquisition of Johnstone contributed revenue of $4.4 million and $3.4 million, respectively, and net income of $0.1 million and $0.7 million, respectively. As a result of the integration of Aarcam into the operations of the Company, it is considered impractical to determine the impact on revenue and net income. However, management estimates that the impact would not have been material.

5Inventories

	March 31, 2011		December 31,  2010
Crude oil	$	102,327	$	131,007
Diluent	8,777		6,788
Asphalt	31,326		25,865
Natural gas liquids	7,203		21,000
Natural gas	30		20
Wellsite fluids and distillate	5,839		10,303
Spare parts and other	2,655		2,500
	$	158,157	$	197,483

The cost of the inventory sold included in cost of sales was $900.5 million and $837.1 million for the three months ended March 31, 2011 and 2010, respectively.

6Net investment in finance leases

The following summarizes the Company’s net investment in arrangements whereby the Company has entered into fixed term contractual arrangements to allow customers to have dedicated use of certain tanks owned by the Company and which are accounted for as finance leases:

	March 31, 2011			December 31, 2010
Total minimum lease payments receivable	$	90,662		$	91,956
Unearned income	(70,220		)	(71,455		)
	20,442			20,501
Less: current portion	236			236
Net investment in finance lease: non-current portion	$	20,206		$	20,265

18

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

7Property, plant and equipment

	Land & Buildings			Pipelines		Tanks			Rolling  Stock			Plant & Equipment			Work in  Progress			Total
Cost:
At January 1, 2011	$	70,006		$	87,247	$	198,412		$	168,404		$	210,614		$	13,088		$	747,771
Additions	42			1,521		1,557			9,502			3,260			6,038			21,920
Disposals	(19		)	—		(145		)	(1,198		)	(48		)	(16		)	(1,426		)
Effect of movements in exchange rates	(20		)	—		(180		)	(872		)	(197		)	(6		)	(1,275		)
At March 31, 2011	$	70,009		$	88,768	$	199,644		$	175,836		$	213,629		$	19,104		$	766,990
Accumulated depreciation and impairment:
At January 1, 2011	$	7,855		$	17,499	$	16,808		$	37,355		$	38,499		$	—		$	118,016
Depreciation	927			2,081		2,721			5,855			4,483			—			16,067
Disposals	(6		)	—		(48		)	(392		)	(17		)	—			(463		)
Effect of movements in exchange rates	(2		)	—		(15		)	(147		)	(5		)	—			(169		)
At March 31, 2011	$	8,774		$	19,580	$	19,466		$	42,671		$	42,960		$	—		$	133,451
Carrying amounts:
At January 1, 2011	$	62,151		$	69,748	$	181,604		$	131,049		$	172,115		$	13,088		$	629,755
At March 31, 2011	61,235			69,188		180,178			133,165			170,669			19,104			633,539

Additions to property, plant and equipment includes capitalization of interest of $0.2 million and $0.3 million for the three months ended March 31, 2011 and 2010, respectively.

In the year ended December 31, 2010, the Company reclassified $32.6 million of property, plant and equipment to assets held for sale, which related to the Edmonton North Terminal. In the three months ended March 31, 2011, the Company completed the sale of the Edmonton North Terminal to Pembina Midstream Limited Partnership for total consideration of $54.3 million, and recorded a gain of $20.4 million. As part of the total consideration received, the Company received pipeline assets valued at $0.9 million that will provide access to crude oil streams within the Edmonton area and assumed obligations related to these assets. Transaction costs related to the sale of $1.4 million were expensed and are included as part of the gain on sale of Edmonton North Terminal.

8Credit Facility

The Company has established with its lenders a revolving credit facility of up to U.S.$200.0 million (the “Credit Facility”), the proceeds of which are available to provide financing for working capital and other general corporate purposes.

The Credit Facility has a term of four years expiring on December 12, 2012. Borrowings under the Credit Facility bear interest at a rate equal to, at the Company’s option, either at LIBOR, the lenders prime rate, the Bankers Acceptance rate or the Above Bank Rate, plus an applicable margin based on a pricing grid. The Company has no amounts drawn against the Credit Facility as at March 31, 2011 and had drawn $43.5 million against the Credit Facility as at December 31, 2010. In addition, the Company has issued letters of credit totalling $82.6 million and $59.2 million as at March 31, 2011 and December 31, 2010, respectively.

19

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Any borrowings under the Credit Facility are secured by the Company’s current assets, including, but not limited to, inventory and accounts receivable.

At March 31, 2011 and December 31, 2010, the Company had restricted cash of $0.5 million and $6.1 million, respectively. The cash is restricted because it has been posted as collateral for certain of the Company’s marketing activities.

9Long-term debt

Long-term debt consists of the following:

	March31,  2011			December31,  2010
First Lien Senior Secured Notes	$	544,208		$	556,976
Senior Notes	194,360			198,920
Debt issue costs and other	(35,917		)	(37,742		)
	$	702,651		$	718,154

On May 27, 2009, the Company issued First Lien Senior Secured Notes (the “First Lien Notes”) in an aggregate principal amount of U.S.$560.0 million. The First Lien Notes have an original term of five years expiring on May 27, 2014, and accrue interest at 11.75% per annum. Throughout the term of the First Lien Notes and under certain conditions, the Company has the option to prepay the principal on the First Lien Notes, at a premium. All borrowings under the First Lien Notes are collateralized by substantially all of the property and equipment and all equity interests.

On January 19, 2010 the Company issued 10.00% unsecured Senior Notes (the “Senior Notes”) in an aggregate principal amount of U.S.$200.0 million. The Senior Notes have an original term of eight years expiring on January 19, 2018, and accrue interest at 10.00% per annum. Throughout the term of the Senior Notes and under certain conditions, the Company has the option to prepay the principal on the Senior Notes, at a premium.

The effective interest rate on the long-term debt, excluding the accretion of debt issuance costs, was 11.0%, and 11.2% for the three months ended March 31, 2011 and 2010 respectively.

In the three months ended March 31, 2011 and 2010, as a result of the movement in exchange rates, the Company recorded a foreign exchange gain on the translation of the U.S. dollar denominated long-term debt of $17.3 million and $20.8 million, respectively.

20

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

10Provisions

The aggregate carrying amounts of the obligation associated with site restoration on the retirement of assets and environmental costs are as follows:

	Three months ended March 31, 2011			Year ended December 31, 2010
Opening balance	$	43,251		$	40,623
Provisions reversed	(461		)	(762		)
Assumed in a business combination	—			2,905
Effect of changes in foreign exchange rates	(16		)	(26		)
Unwinding of discount	398			1,543
Reclassified to liabilities related to assets held for sale	—			(1,032		)
Closing balance	$	43,172		$	43,251

The Company currently estimates the total undiscounted future value amount, including an inflation factor of 2%, of estimated cash flows to settle the future liability for asset retirement and remediation obligations to be approximately $164.9 million at March 31, 2011. In order to determine the current provision related to these future values, the estimated future values are discounted using a risk-free rate of 4%. The provision is expected to be settled up to 40 years into the future.

The Company is not aware of any potential unasserted environmental remediation claims that may be brought against it. Accruals are recorded when environmental remediation is probable and the costs can be reasonably estimated. A number of factors affect the cost of environmental remediation, including the determination of the extent of contamination, the length of time remediation may require, the complexity of environmental regulations and the advancement of remediation technology. Considering these factors, the Company has estimated the costs of remediation, which will be incurred in future years. The Company believes the provisions made for environmental matters are adequate, however it is reasonably possible that actual costs may exceed the estimated accrual, if the selected methods of remediation do not adequately reduce the contaminates and further remedial action is required.

11Other long-term liabilities

	March 31, 2011		December 31, 2010
Post-retirement benefits	$	4,021	$	3,958
Accrued pension liability	2,613		2,487
	$	6,634	$	6,445

21

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

12Commitments and contingencies

Contingencies

Two subsidiaries of the Company are currently undergoing two income tax related audits. While the final outcome of such audits cannot be predicted with certainty, it is the opinion of management that the resolution of these audits will not have a material impact on the Company’s consolidated financial position or results of operations. As part of the acquisition of the Company by Riverstone from Hunting PLC (“Hunting”), Hunting has indemnified the Company for the pre-closing period impact of these audits. Included in income tax receivable and accounts payable and accrued charges as at December 31, 2010 and March 31, 2011 is $53.7 million, whereby Hunting paid the Company and the Company paid the tax assessments relative to these audits.  In the three months ended March 31, 2010 income tax payments of $20.5 million were funded by Hunting.

The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to the contractual agreements and management decisions, result in the recognition of estimated asset retirement obligations. Estimates of asset retirement obligation costs can change significantly based on such factors as operating experience and changes in legislation and regulations.

The Company is involved in various legal actions, which have occurred in the ordinary course of business. Management is of the opinion that losses, if any, arising from such legal actions would not have a material impact on the Company’s consolidated financial position or results of operations.

13Revenue

	Three months ended March 31,
	2011		2010
Products	$	1,016,269	$	882,020
Services	131,748		82,509
	$	1,148,017	$	964,529

14Depreciation and amortization

	Three months ended March 31,
	2011		2010
Depreciation of property, plant and equipment	$	16,067	$	12,958
Amortization of intangible assets	7,739		5,717
	$	23,806	$	18,675

Depreciation of property, plant and equipment and amortization of intangible assets have been expensed as follows:

	Three months ended March 31,
	2011		2010
Cost of sales	$	23,035	$	17,992
General and administrative	771		683
	$	23,806	$	18,675

22

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

15Employee salaries and benefits

	Three months ended March 31,
	2011		2010
Employee salaries and benefits	$	27,417	$	26,160

Employee salaries and benefits have been expensed as follows:

	Three months ended March 31,
	2011		2010
Cost of sales	$	23,505	$	20,884
General and administrative	3,912		5,276
	$	27,417	$	26,160

Included in employee benefits is stock based compensation of $0.6 million and $1.2 million for the three months ended March 31, 2011 and 2010, respectively. The stock based compensation expense is included in general and administrative expenses.

16   Other operating expenses

	Three months ended March 31,
	2011			2010
Loss (gain) on sale of property, plant and equipment	$	(98	)	$	4
Foreign exchange loss	1,274			531
	$	1,176		$	535

23

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

17Income tax provision

The income tax provision differs from the amounts, which would be obtained by applying the combined Canadian base federal and provincial income tax rate to income before income taxes. These differences result from the following items:

	Three months ended March 31,
	2011			2010
Income before income taxes	$	48,233		$	14,148
Statutory income tax rate	26.5		%	28.0		%
Computed income tax provision	12,782			3,961
Increase (decrease) in income tax resulting from:
Foreign exchange gain	(574		)	(728		)
Non-taxable portion of capital gain	(2,870		)	—
Non-deductible expenses	40			—
Stock based compensation	217			345
Rate differential on foreign taxes	229			—
Non-taxable dividends	(925		)	—
Other, including revisions in previous tax estimates	(32		)	28
Rate reduction due to partnership deferral	(765		)	(439		)
	$	8,102		$	3,167
Effective income tax rate	16.8		%	22.4		%

24

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

18Related party transactions

On December 12, 2008, the Company entered into a management agreement with Riverstone, whereby Riverstone provides management advisory services in connection with the general business operations of the Company. Total management fees and expenses for the three months ended March 31, 2011 and 2010 was $0.3 million and $0.3 million, respectively. These amounts are included in general and administrative expenses on the statement of income.

Other related party transactions include:

	Transaction Value
	Three months ended					Balance outstanding as of
	March 31, 2011		March 31, 2010			March 31, 2011		December 31, 2010
Sale of goods and services
Parent having controlling/significant interest	$	227	$	2		$	124	$	—
Associates	991		1,076			106		156
Purchase of goods and services
Parent having controlling/significant interest	$	12,406	$		50	$	8,586	$	13,043
Associates	3,899		3,441			2,095		1,412

The related party transactions noted above have been measured at agreed upon market based terms.

19Stock based compensation plan

During the year ended December 31, 2009, the Board of Directors adopted the Equity Incentive Plan (the “Plan”). The Company reserved a total of 59,739 shares for grants under the Plan. The Plan provides for the issuance of stock options, stock appreciation rights, restricted stock and restricted stock units to employees, directors, consultants, and other associates. As of March 31, 2011, the Company has only issued stock options to employees participating in the Plan. The options generally vest in equal tranches annually over a period of five years from the date of grant and have a maximum term of ten years. The Company has granted both traditional time-vesting stock options and performance vesting stock options under the Plan. The performance vesting stock options vest and expire under the same terms and service conditions as the time-vesting stock options, with vesting subject to the Company attaining prescribed performance relative to predetermined key financial measures.

The stock based compensation expense is included in general and administrative expenses and was $0.6 and $1.2 million for the three months ended March 31, 2011 and 2010, respectively.

A summary of activity under the Plan is set forth below.

	Options Outstanding
	Options Available for Grant		Numbers of Shares		Weighted- Average Exercise Price (in dollars)
Balance at December 31, 2010	2,225		57,514		$	1,000
Granted	(360	)	360		1,000
Forfeited	1,449		(1,449	)	1,000
Balance at March 31, 2011	3,314		56,425		$	1,000

25

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

At March 31, 2011 and December 31, 2010, total outstanding options vested under the Plan were 15,536 and 15,536, respectively, at a weighted-average exercise price of $1,000.

20Financial instruments

The Company has financial instruments other than financial contracts consisting of cash and cash equivalents, trade and other receivables, trade payables and accrued charges, Credit Facility and long-term debt. Cash and cash equivalents and trade and other receivables are recorded at amortized cost which approximates fair value due to the short term nature of the instrument. Trade payables and accrued charges are designated as other liabilities recorded at amortized cost. The fair value of trade payables and accrued charges approximate their carrying values due to the short term nature of these instruments. Long term debt is designated as other liabilities and held at amortized cost using the effective interest method of amortization. The estimated fair market value of long-term debt at March 31, 2011 and December 31, 2010, based on market information, was U.S. $833.4 million and U.S. $821.8 million, respectively.

Fair Values

The following is a summary of the Company’s risk management contracts outstanding at March 31, 2011:

(i)Commodity financial instruments

The Company has entered into crude oil futures and swap contracts to manage the price risk associated with sales, purchases and inventories of crude oil and petroleum products. One contract corresponds to 1,000 barrels (“bbls”).

(a)WTI Futures

Term	Contract	Volume (Contracts) bbls	Weighted Average U.S.$/unit		Fair Value
November 2011-January 2012	Bought Futures	30	$	98.86
April 2011 – January 2012	Sold Futures	65	102.99
					$	(7	)

(b)OTC WTI Asian Options

Term	Contract	Volume (bbls)	Sold call U.S.$/bbl		Bought put U.S.$/bbl		Fair value
June 1, 2011 – June 30, 2011	Collar	50	$	120.25	$	100.00
June 1, 2011 – June 30, 2011	Collar	25	108.50		98.00
June 1, 2011 – June 30, 2011	Collar	25	108.00		100.00
June 1, 2011 – June 30, 2011	Collar	25	108.60		99.00
June 1, 2011 – June 30, 2011	Collar	25	109.00		99.00
June 1, 2011 – June 30, 2011	Collar	25	110.50		100.00
June 1, 2011 – June 30, 2011	Collar	25	112.00		100.00
							$	(384	)

26

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

(c)Natural Gas Liquids (NGL)

The Company has entered into NGL swap contracts to manage the risk associated with sales, purchases and inventories of NGLs.

ClearPort-WTI to Mt. Belvieu Propane Swaps

Term	Contract	Volume (bbls)	U.S.$/bbl		Fair Value
April 2011 – December 2011	Sold WTI	5	$	83.77
	Bought Propane	10	40.95
April 2011 – September 2011	Bought WTI	5	77.31
	Sold Propane	10	39.59
October 2011 – December 2011	Bought WTI	5	95.17
	Sold Propane	10	52.34
January 2012 – December 2012	Bought WTI	10	101.85
	Sold Propane	20	56.02
January 2012 – December 2012	Sold WTI	3	104.70
	Bought Propane	5	54.44
					$	573

ClearPort- WTI to Mt. Belvieu Natural Gasoline Swap

Term	Contract	Volume (bbls)	U.S.$/bbl		Fair Value
October 2011 – December 2011	Bought WTI	30	$	97.66
	Sold Natural Gasoline	30	94.08
October 2011 – December 2011	Sold WTI	30	106.25
	Bought Natural Gasoline	30	101.64
					$	88

ClearPort-WTI to Mt. Belvieu Butane Swaps

Term	Contract	Volume (bbls)	U.S.$/bbl		Fair Value
April 2011 – December 2011	Sold WTI	38	$	84.49
	Bought Butane	55	59.97
April 2011 – December 2011	Bought WTI	38	82.42
	Sold Butane	55	59.35
April 2011 – March 2012	Sold WTI	15	96.62
	Bought Butane	20	69.86
April 2011 – March 2012	Bought WTI	15	95.77
	Sold Butane	20	71.30
					$	1,015

ClearPort-WTI to Mt. Belvieu Butane Swaps to Mt. Belvieu ISO Butane Swaps

Term	Contract	Volume (bbls)	U.S.$/bbl		Fair Value
April 2011 – March 2012	Sold WTI	7	$	104.48
	Bought Butane	7	75.39
	Bought ISO Butane	3	78.33
					$	174

27

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

ClearPort — Mt. Belvieu Propane to Mt. Belvieu Natural Gasoline Swap

Term	Contract	Volume (bbls)	U.S.$/bbl		Fair Value
October 2011 – December 2011	Sold Propane	20	$	55.65
	Bought Natural Gasoline	11	95.76
October 2011 – December 2011	Bought Propane	20	58.33
	Sold Natural Gasoline	11	102.43
					$	57

Mt. Belvieu Natural Gasoline Swaps

Term	Contract	Volume (bbls)	U.S.$/bbl		Fair Value
October 2011 – December 2011	Bought Fixed Price	10/mth	$	93.28
October 2011 – December 2011	Sold Fixed Price	10/mth	93.56
					$	8

(d)Electricity Price Swap

The Company is a party to a financial swap contract to fix the level of anticipated electricity costs that are price sensitive to the Alberta Electric System Operator (AESO) Pool Price. If the actual AESO Pool Price is greater than $80.49 /megawatt hour the Company receives the difference between that price and $80.49. If the actual AESO Pool Price is less than $80.49, the Company pays the difference between that price and $80.49. The contract is for 3 megawatts, 24 hours per day, seven days per week, with a remaining term to December 31, 2012.

AESO electricity swap

Term	Contract	Volume Megawatt hour /day	$/ Megawatt hour		Fair Value
April 1, 2011 – December 31, 2012	Bought Fixed Price	72	$	80.49	$	(573	)

(ii)Currency financial instruments

The Company has entered into forward contracts to sell U.S. dollars in exchange for Canadian dollars to fix the exchange rate on its estimated future net cash flows denominated in U.S. dollars. The Company has also entered into forward contracts to help mitigate the exposure on its U.S. dollar interest payments on the long-term debt.

USD Dollar Forwards

Term	Contract	Volume U.S.$	Weighted average exchange rate (CAD$/U.S.$)		Fair value
April 25, 2011	Forward sell	80,000	$	0.9773
May 31, 2011	Forward buy	28,000	0.9796
					$	418

28

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

The Company’s financial instruments consist of financially settled commodity futures, options swap contracts, foreign currency forward contracts and foreign currency options. The value of the Company’s risk management contracts are determined using inputs that are either readily available in public markets or are quoted by counterparties to these contracts. In situations where the Company obtains inputs via quotes from its counterparties, these quotes are verified for reasonableness via similar quotes from another source for each date for which financial statements are presented. The Company has consistently applied these valuation techniques in all periods presented and the Company believes it has obtained the most accurate information available for the types of financial instrument contracts held. The Company has categorized the inputs for these contracts as Level 1, defined as observable inputs such as quoted prices in active markets; Level 2 defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; or Level 3 defined as unobservable inputs in which little or no market data exists therefore requiring an entity to develop its own assumptions.

The fair value of financial instrument contracts at March 31, 2011 was:

	Total		Level 1		Level 2		Level 3
Assets from commodity financial instrument contracts
Commodity futures	$	4	$	4	$	—	$	—
Commodity options	122		—		122		—
Commodity swaps	3,009		—		3,009		—
Electricity swaps	10		—		10		—
Foreign currency forward contracts and options	709		—		709		—
Total assets	$	3,854	$	4	$	3,850	$	—
Liabilities from commodity financial instrument contracts
Commodity futures	$	11	$	11	$	—	$	—
Commodity options	506		—		506		—
Commodity swaps	1,094		—		1,094		—
Electricity swaps	583		—		583		—
Foreign currency forward contracts and options	291		—		291		—
Total liabilities	$	2,485	$	11	$	2,474	$	—

The fair value of financial instrument contracts at December 31, 2010 was:

	Total		Level 1		Level 2		Level 3
Assets from commodity financial instrument contracts
Commodity swaps	$	1,029	$	—	$	1,029	$	—
Foreign currency forward contracts and options	783		—		783		—
Total assets	$	1,812	$	—	$	1,812	$	—
Liabilities from commodity financial instrument contracts
Commodity futures	$	1,599	$	1,599	$	—	$	—
Commodity swaps	122		—		122		—
Electricity swaps	1,463		—		1,463		—
Foreign currency forward contracts and options	68		—		68		—
Total liabilities	$	3,252	$	1,599	$	1,653	$	—

29

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

The impact of financial instruments has been expensed in the statement of income as follows:

	Three months ended March 31,
	2011			2010
Cost of sales	$	(1,664	)	$	(2,277	)
Interest expense	224			—
	$	(1,440	)	$	(2,277	)

Financial Risk Management

The Company’s activities expose it to certain financial risks, including foreign exchange risk, interest rate risk, commodity price risk, credit risk and liquidity risk. The Company’s risk management strategy seeks to minimize potential adverse effects on its financial performance. As part of its strategy, both primary and derivative financial instruments are used to hedge its risk exposures.

There are clearly defined objectives and principles for managing financial risk, with policies, parameters and procedures covering the specific areas of funding, banking relationships, interest rate exposures and cash management. The Company’s treasury function is responsible for implementing the policies and providing a centralised service to the Company for identifying evaluating and monitoring financial risks.

a)Foreign Exchange Risk

Foreign exchange risks arise from future transactions and cash flows and from recognized monetary assets and liabilities that are not denominated in the functional currency of the Company’s operations.

The exposure to exchange rate movements in significant future transactions and cash flows is managed using forward foreign exchange contracts, currency options and currency swaps. These financial instruments have not been designated in a hedge relationship. No speculative positions are entered into by the Company.

Foreign currency exchange rate sensitivity

At March 31, 2011, if the Canadian dollar strengthened or weakened by 5% relative to the U.S. dollar and all other variables, in particular interest rates remain constant, the impact on net income would be as follows:

	Three months ended March 31,
	2011						2010
	Net Income			Equity			Net Income			Equity
USD Forwards
Favorable 5% Change	$	1,872		$	1,872		$	1,139		$	1,139
Unfavorable 5% Change	(1,872		)	(1,872		)	(1,139		)	(1,139		)
Long-term debt
Favorable 5% Change	$	31,759		$	31,759		$	33,190		$	33,190
Unfavorable 5% Change	(31,759		)	(31,759		)	(33,190		)	(33,190		)

30

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

The movement is a result of a change in the fair value of U.S. dollar forward contracts, which have not been designated as a hedge, and also the change in the carrying value of the Company’s U.S. dollar denominated long-term debt.

The impact of translating the net assets of our U.S operations into Canadian dollars is excluded from this sensitivity analysis.

b)Interest Rate Risk

Interest rate risk is the risk that the value of a financial instrument will be affected by changes in market interest rates.  Existing long-term debt accrues interest at fixed interest rates and, consequently, has no exposure to changes in market interest rates. Under the Credit Facility, the Company is subject to interest rate risk as borrowings bear interest at a rate equal to at the Company’s option either LIBOR the prime rate the Bankers Acceptance rate or the Above Bank Rate plus an applicable margin based on a pricing grid. A change of 1% in the interest rate would have had an immaterial impact on net income and equity in both the current and prior period. The Company’s interest rate risk exposure does not exist within any of the operating segments, but exists at the corporate level where the variable rate debt obligations are issued.

c)Commodity price risk

The Company is exposed to changes in the price of oil, oil related products, natural gas and electricity commodities, which are monitored regularly. Oil and gas price futures, options and swaps are used to manage the exposure to oil and gas price movements. These financial instruments are not designated as a hedge. An electricity price swap is used to manage the exposure to electricity prices in Canada and is marked to market each period. Based on the Company’s risk management policies, all of the financial instruments are employed in connection with an underlying asset liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices.

The following table summarizes the change in fair value of the Company’s risk management positions to fluctuations in commodity prices leaving all other variables constant. The Company believes a 15% volatility in crude oil related prices and a 10% volatility in electricity prices are reasonable assumptions. This analysis assumes that all other variables in particular foreign currency rates remain constant.

	Three months ended March 31,
	2011						2010
	Net Income			Equity			Net Income			Equity
Crude oil related prices
Favorable 15% Change	$	2,139		$	2,139		$	4,820		$	4,820
Unfavorable 15% Change	(2,697		)	(2,697		)	(4,820		)	(4,820		)
Electricity prices
Favorable 10% Change	$	226		$	226		$	265		$	265
Unfavorable 10% Change	(226		)	(226		)	(265		)	(265		)

31

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

d)Credit risk

The Company’s credit risk arises from its outstanding trade receivables. A significant portion of the Company’s trade receivables are due from entities in the oil and gas industry. Concentration of credit risk is mitigated by having a broad customer base and by dealing with credit-worthy counterparties in accordance with established credit approval practices. The Company actively monitors the financial strength of its customers and in select cases has tightened credit terms to minimize the risk of default on accounts receivable. In addition, the Company maintains trade receivable insurance for eligible customers with an approved credit limit from $0.2 million to $10.0 million.

The movement in the allowance for doubtful accounts in respect of trade and other receivables was as follows:

	Three months ended March 31,
	2011			2010
Opening balance	$	2,157		$	386
Accounts receivable write off	—			(12		)
Additional allowances	1,609			2
Effect of movement in exchange rates	(12		)	—
Ending balance	$	3,754		$	376

At March 31, 2011 and December 31, 2010 approximately 6% and 7% respectively of net trade receivables are past due but not considered to be impaired. The maximum exposure to credit risk related to trade receivables is their carrying value as disclosed in the financial statements.

The Company establishes guidelines for customer credit limits and terms. The Company review includes external ratings when available and financial statements. Customers that are considered as “high risk” are closely monitored and future sales may be made on a prepayment or collateralized basis. However, the Company does not generally require collateral in respect of trade and other receivables. The Company provides adequate provisions for expected losses from the credit risks associated with trade receivables. The provision is based on an individual account-by-account analysis and prior credit history.

The Company is exposed to credit risk associated with possible non-performance by financial instrument counterparties. The Company does not generally require collateral from its counterparties but believes the risk of non-performance is minimal. The counterparties are major financial institutions or commodity brokers with investment grade credit ratings as determined by recognized credit rating agencies.

The Company’s cash equivalents are placed in high-quality commercial paper money market funds and time deposits with major international banks and financial institutions.

e)Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. This risk relates to the Company’s ability to generate or obtain sufficient cash or cash equivalents to satisfy these financial obligations as they become due. The Company’s process for managing liquidity risk include preparing and monitoring capital and operating budgets, coordinating and authorizing project expenditures and authorization of contractual agreements. The Company seeks additional financing based on the results of these processes. The budgets are updated with forecasts when required, and as conditions change. Sufficient funds and the Credit

32

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Facility are available to satisfy both the Company’s long and short-term requirements. The Credit Facility totals U.S.$200.0 million and at March 31, 2011 there was no amount drawn against the facility.

The terms of the Credit Facility require the Company to comply with financial covenants when the available amount under the facility is less than 15% of the facility, including maintaining a fixed charge coverage ratio. If the Company fails to comply with this covenant the lenders may declare an event of default under the facility. At March 31, 2011 this covenant is not applicable.

Set out below is maturity analyses of certain of the Company’s financial liabilities as recorded on the balance sheet at March 31, 2011. The maturity dates are the contractual maturities of the financial liabilities and the amounts are the contractual undiscounted cash flows.

Financial Liabilities	On demand or within one year		Between one and five years		After five years		Total
Non-financial instrument liabilities
Trade payables and accrued charges	$	392,744	$	—	$	—	$	392,744
Long-term debt	—		544,208		194,360		738,568
Accrued interest on long-term debt	25,660		—		—		25,660
	$	418,404	$	544,208	$	194,360	$	1,156,972
Financial instrument liabilities
Commodity futures	$	11	$	—	$	—	$	11
Commodity options	506		—		—		506
Commodity swaps	1,061		33		—		1,094
Electricity swaps	286		297		—		583
Foreign currency forward contracts	291		—		—		291
Total financial liabilities	$	2,155	$	330	$	—	$	2,485

Capital management

The Company’s objectives when managing its capital structure are to maintain financial flexibility so as to preserve the Company’s ability to meet its financial obligations and to finance internally generated growth as well as potential acquisitions.

The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include shareholders’ equity, long-term debt, the Credit Facility and working capital. To maintain or adjust the capital structure, the Company may raise debt and/or adjust its capital spending to manage its current and projected debt levels.

Financing decisions are made by management and the Board of Directors based on forecasts of the expected timing and level of capital and operating expenditure required to meet the Company’s commitments and development plans. Factors considered when determining whether to issue new debt or to seek equity financing include the amount of financing required, the availability of financial resources, the terms on which financing is available and consideration of the balance between shareholder value creation and prudent financial risk management.

33

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Net debt is calculated as total borrowings (including ‘current and non-current borrowings’ as shown in the consolidated statement of financial position), less cash and cash equivalents. Total capital is calculated as net debt plus share capital as shown in the consolidated balance sheet.

	March 31, 2011			December 31, 2010
Total financial liability borrowings	$	702,651		$	761,654
Less: cash and cash equivalents	(51,989		)	(7,225		)
Net debt	650,662			754,429
Total share capital	668,827			664,724
Total capital	$	1,319,489		$	1,419,153

If the Company is in a net debt position, the Company will assess whether the projected cash flow and availability under the Credit Facility is sufficient to service this debt and support ongoing operations. Consideration will be given to reducing the total debt or raising funds through an alternative route such as issuing common shares.

34

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

21Segmental information

The Company has defined its operations into the following operating segments: (i) Terminals and Pipelines, (ii) Truck Transportation, (iii) Propane and NGL Marketing and Distribution, (iv) Processing and Wellsite Fluids, and (v) Marketing.

Terminals and pipelines includes the tariff-based pipeline services and fee-based storage and terminalling services for crude oil, condensate and refined products. The Company owns and operates pipelines and custom blending terminals, which are strategically located throughout Alberta and Saskatchewan, injection stations, which are located in the United States and major storage terminals located at Edmonton and Hardisty, which are the principal hubs for aggregating and exporting oil and refined products out of the Western Canadian Sedimentary Basin.

Truck transportation includes the hauling services for crude, condensate, propane, butane, asphalt, methanol, sulfur, petroleum coke, gypsum and drilling fluids to customers in Western Canada and the United States.

Propane and NGL marketing and distribution includes a retail propane distribution operation and a wholesale business that includes a wholesale propane distribution and an NGL marketing business. The retail operations sell propane to oil and gas, industrial and residential customers, while the wholesale operations sell to larger customers who are not usually end users of the product.

Processing and wellsite fluids includes the refining and marketing of a variety of products, including several grades of road asphalt, roofing flux, wellsite fluids and tops.

Marketing includes the purchasing, selling, storing, and blending of crude oil and condensate, taking advantage of specific location, quality, or time-based arbitrage opportunities.

These operating segments of the Company have been derived because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the Company’s chief operating decision makers to make decisions about resources to be allocated to each segment and assess its performance; and (c) for which discrete financial information is available. No operating segments were aggregated to arrive at the reportable segments.

Inter-segmental transactions are eliminated upon consolidation. No margins are recognized on inter-segmental transactions.

Accounting policies used for segment reporting are consistent with the accounting policies used for the preparation of the Company’s consolidated financial statements.

35

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Three months endedMarch 31, 2011	Terminals & Pipelines			Truck Transportation			Propane & NGL Marketing & Distribution			Processing & Wellsite Fluids			Marketing			Corporate & other reconciling balances			Total
Statement of income
Revenue - external and inter-segmental	$	222,825		$	107,618		$	268,972		$	119,359		$	815,780		$	—		$	1,534,554
Revenue - inter-segmental	(187,658		)	(14,161		)	(26,725		)	(36,249		)	(121,744		)	—			(386,537		)
Revenue - external	35,167			93,457			242,247			83,110			694,036			—			1,148,017
Segment profit	16,736			16,236			17,548			11,128			4,826			—			66,474
Depreciation of property, plant and equipment	6,037			5,975			2,000			1,608			41			406			16,067
Amortization of intangible assets	531			3,399			1,563			1,711			170			365			7,739
General and administrative	—			—			—			—			—			5,982			5,982
Stock based compensation	—			—			—			—			—			621			621
Gain on sale of Edmonton North	—			—			—			—			—			(20,370		)	(20,370		)
Corporate foreign exchange loss	—			—			—			—			—			883			883
Interest expense	—			—			—			—			—			24,705			24,705
Interest income	—			—			—			—			—			(58		)	(58		)
Other financing expense	—			—			—			—			—			(17,328		)	(17,328		)
Income tax expense	—			—			—			—			—			8,102			8,102
Net income	$	10,168		$	6,862		$	13,985		$	7,809		$	4,615		$	(3,308	)	$	40,131
Total assets	$	552,200		$	317,829		$	307,209		$	336,389		$	345,377		$	156,373		$	2,015,377
Total liabilities	21,028			35,982			60,915			29,064			280,443			1,005,884			1,433,316

36

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

Three months endedMarch 31, 2010	Terminals & Pipelines			Truck Transportation			Propane & NGL Marketing & Distribution			Processing & Wellsite Fluids			Marketing			Corporate & other reconciling balances			Total
Statement of income
Revenue - external and inter-segmental	$	282,167		$	66,012		$	174,116		$	120,521		$	870,724		$	—		$	1,513,540
Revenue - inter-segmental	(270,730		)	(15,965		)	(32,031		)	(27,875		)	(202,410		)	—			(549,011		)
Revenue - external	11,437			50,047			142,085			92,646			668,314			—			964,529
Segmental profit	8,382			9,622			13,175			9,143			2,634			—			42,956
Depreciation of property, plant and equipment	5,053			3,995			1,688			1,524			524			174			12,958
Amortization of intangible assets	477			1,783			965			1,814			169			509			5,717
General and administrative	—			—			—			—			—			6,237			6,237
Stock based compensation	—			—			—			—			—			1,150			1,150
Foreign exchange gain	—			—			—			—			—			(274		)	(274		)
Interest expense	—			—			—			—			—			24,036			24,036
Interest income	—			—			—			—			—			(216		)	(216		)
Other financing income	—			—			—			—			—			(20,800		)	(20,800		)
Income tax expense	—			—			—			—			—			3,167			3,167
Net income	$	2,852		$	3,844		$	10,522		$	5,805		$	1,941		$	(13,983	)	$	10,981
Total assets	$	469,741		$	210,847		$	263,755		$	326,435		$	307,874		$	266,519		$	1,845,171
Total liabilities	16,112			25,354			46,408			33,408			167,243			999,937			1,288,462

Geographic Data

Based on the location of the end user, approximately 21% and 13% of revenue was to customers in the United States for the three months ended March 31, 2011 and 2010, respectively.

The Company’s long lived assets are primarily concentrated in Canada with 11% in the United States at both March 31, 2011 and December 31, 2010.

22   Transition to IFRS

As stated in note 2, effective January 1, 2011, the Company began reporting under IFRS, and the accounting policies disclosed in note 3 have been applied in preparing the financial statements for the three month ended March 31, 2011 and 2010, for the year ended December 31, 2010, and in the preparation of the Company’s opening balance sheet at January 1, 2010, the transition date.

In preparing the opening IFRS balance sheet, the Company has adjusted amounts reported previously in financial statements prepared in accordance with Canadian GAAP. An explanation of how the transition from Canadian GAAP to IFRS has affected the Company’s financial position, financial performance and cash flows is set out in the following tables and the notes that accompany the tables.

37

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

(i)Reconciliation of assets, liabilities and equity as previously reported under Canadian GAAP to IFRS

	As at December 31, 2010
	Canadian GAAP			Adjustments				IFRS
Assets
Current assets
Cash and cash equivalents	$	7,225		$	—			$	7,225
Trade and other receivables	354,682			—				354,682
Income taxes receivable	57,130			—				57,130
Inventories	197,483			—				197,483
Prepaid expenses and other assets	8,749			(906		)	(h)	7,843
Net investment in finance leases	236			—				236
Assets held for sale	32,985			611			(c)	33,596
Total current assets	658,490			(295		)		658,195
Non-current assets
Deferred income tax assets	13,422			—				13,422
Long-term prepaid expenses and other assets	24,276			(2,286		)	(h)	21,990
Net investment in finance leases	20,265			—				20,265
Property, plant and equipment	652,885			(36,745		)	(a)	629,755
				14,398			(c)
				1,488			(d)
				(4,852		)	(g)
				3,192			(h)
				(611		)	(c)
Intangible assets	154,610			(7,123		)	(b)	152,339
				4,852			(g)
Goodwill	498,817			(2,401		)	(f)	496,416
Total non-current assets	1,364,275			(30,088		)		1,334,187
Total assets	$	2,022,765		$	(30,383	)		$	1,992,382
Liabilities
Current liabilities
Credit Facility	$	43,500		$	—			$	43,500
Trade payables and accrued charges	393,686			—				393,686
Deferred revenue	54,701			—				54,701
Income taxes payable	1,217			—				1,217
Deferred income tax liabilities	177			(177		)	(i)	—
Liabilities related to assets held for sale	2,960			802			(c)	3,762
Total current liabilities	496,241			625				496,866
Non-current liabilities
Long-term debt	718,154			—				718,154
Provisions	22,045			21,206			(c)	43,251
Other long-term liabilities	3,224			3,221			(e)	6,445
Deferred income tax liabilities	196,440			(13,582		)	(i)	182,858
Total non-current liabilities	939,863			10,845				950,708
Total liabilities	1,436,104			11,470				1,447,574
Equity
Share capital	664,724			—				664,724
Contributed surplus	13,586			—				13,586
Accumulated other comprehensive loss	(6,767		)	(575		)	(e)	(7,342		)
Deficit	(84,882		)	(41,278		)	(k)	(126,160		)
Total equity	586,661			(41,853		)		544,808
Total liabilities and shareholder’s equity	$	2,022,765		$	(30,383	)		$	1,992,382

38

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

	As at March 31, 2010
	Canadian GAAP			Adjustments				IFRS
Assets
Current assets
Cash and cash equivalents	$	185,542		$	—			$	185,542
Trade and other receivables	322,287			—				322,287
Income taxes receivable	33,780			—				33,780
Inventories	123,121							123,121
Prepaid expenses and other assets	6,292			(884		)	(h)	5,408
Total current assets	671,022			(884		)		670,138
Non-current assets
Deferred income tax assets	5,225			—				5,225
Long-term prepaid expenses and other assets	30,507			(2,123		)	(h)	28,384
Property, plant and equipment	602,817			(39,233		)	(a)	575,128
				12,726			(c)
				538			(d)
				(4,727		)	(g)
				3,007			(h)
Intangible assets	129,726			(9,013		)	(b)	125,440
				4,727			(g)
Goodwill	440,898			(42		)	(f)	440,856
Total non-current assets	1,209,173			(34,140		)		1,175,033
Total assets	$	1,880,195		$	(35,024	)		$	1,845,171
Liabilities
Current liabilities
Trade payables and accrued charges	$	318,529		$	—			$	318,529
Deferred income tax liabilities	839			(839		)	(i)	—
Total current liabilities	319,368			(839		)		318,529
Non-current liabilities
Long-term debt	728,981			—				728,981
Provisions	21,432			19,505			(c)	40,937
Other long-term liabilities	3,181			2,775			(e)	5,956
Deferred income tax liabilities	207,546			(13,487		)	(i)	194,059
Total non-current liabilities	961,140			8,793				969,933
Total liabilities	1,280,508			7,954				1,288,462
Equity
Share capital	654,061			—				654,061
Contributed surplus	10,107			—				10,107
Deficit	(64,481		)	(42,978		)	(k)	(107,459		)
Total equity	599,687			(42,978		)		556,709
Total liabilities and shareholder’s equity	$	1,880,195		$	(35,024	)		$	1,845,171

39

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

	As at January 1, 2010
	Canadian GAAP			Adjustments				IFRS
Assets
Current assets
Cash and cash equivalents	$	26,263		$	—			$	26,263
Trade and other receivables	315,865			—				315,865
Income taxes receivable	15,541			—				15,541
Inventories	113,688			—				113,688
Deferred income tax asset	1,509			(1,509		)	(i)	—
Prepaid expenses and other assets	5,187			(1,142		)	(h)	4,045
Total current assets	478,053			(2,651		)		475,402
Non-current assets
Deferred income tax assets	5,225			1,509			(i)	6,734
Long-term prepaid expenses and other assets	30,941			(1,909		)	(h)	29,032
Property, plant and equipment	598,826			(40,062		)	(a)	570,307
				12,807			(c)
				282			(d)
				(4,597		)	(g)
				3,051			(h)
Intangible assets	126,955			(9,643		)	(b)	121,909
				4,597			(g)
Goodwill	433,894			—				433,894
Total non-current assets	1,195,841			(33,965		)		1,161,876
Total assets	$	1,673,894		$	(36,616	)		$	1,637,278
Liabilities
Current liabilities
Credit Facility	$	25,000		$	—			$	25,000
Trade payables and accrued charges	254,869			—				254,869
Deferred revenue	13,405			—				13,405
Income taxes payable	8,443			—				8,443
Deferred income tax liabilities	839			(839		)	(i)	—
Total current liabilities	302,556			(839		)		301,717
Non-current liabilities
Long-term debt	553,942			—				553,942
Provisions	21,302			19,321			(c)	40,623
Other long-term liabilities	3,077			2,818			(e)	5,895
Deferred income tax liabilities	204,373			(13,850		)	(i)	190,523
Total non-current liabilities	782,694			8,289				790,983
Total liabilities	1,085,250			7,450				1,092,700
Equity
Share capital	650,690			—				650,690
Contributed surplus	8,957			—				8,957
Deficit	(71,003		)	(44,066		)	(k)	(115,069		)
Total equity	588,644			(44,066		)		544,578
Total liabilities and shareholder’s equity	$	1,673,894		$	(36,616	)		$	1,637,278

40

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

(ii)Reconciliation of comprehensive income (loss) as previously reported under Canadian GAAP to IFRS

The following is a reconciliation of the Company’s statement of income for the year ended December 31, 2010 and the three months ended March 31, 2010. Amounts shown under Canadian GAAP have been re-classified to conform to the presentation under IFRS, including depreciation of property, plant and equipment, amortization of intangible assets, accretion expense and stock based compensation.

	Year ended December 31, 2010
	Canadian GAAP			Adjustments				IFRS
Revenue	$	3,677,988		$	12,464		(j)	$	3,690,452
Cost of sales	3,597,939			(3,317		)	(a)	3,604,958
				(2,520		)	(b)
				339			(c)
				53			(d)
				12,464			(j)
Gross profit	80,049			5,445				85,494
General and administrative	32,329			(172		)	(e)	34,558
				2,401			(f)
Other operating expenses	(3,157		)	—				(3,157		)
Income from operating activities	50,877			3,216				54,093
Loss from investments in associates	914			—				914
Interest expense	100,238			757			(c)	99,736
				(1,259		)	(d)
Interest income	(324		)	—				(324		)
Foreign exchange gain on long-term debt	(36,760		)	—				(36,760		)
Loss before income taxes	(13,191		)	3,718				(9,473		)
Income tax recovery	(13,346		)	929			(i)	(12,415		)
Net income	155			2,787				2,942
Other comprehensive loss
Cumulative translation adjustment, net of tax	(6,767		)	—				(6,767		)
Comprehensive loss	$	(6,612	)	$	2,787			$	(3,825	)

41

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

	Three months ended March 31, 2010
	Canadian GAAP			Adjustments				IFRS
Revenue	$	964,237		$	292		(j)	$	964,529
Cost of sales	939,328			(829		)	(a)	938,252
				(630		)	(b)
				81			(c)
				10			(d)
				292			(j)
Gross profit	24,909			1,368				26,277
General and administrative	8,071			(43		)	(e)	8,070
				42			(f)
Other operating expenses (income)	535			—				535
Income from operating activities	16,303			1,369				17,672
Loss from investment in associates	504			—				504
Interest expense	24,118			184			(c)	24,036
				(266		)	(d)
Interest income	(216		)	—				(216		)
Foreign exchange gain on long-term debt	(20,800		)	—				(20,800		)
Income before income taxes	12,697			1,451				14,148
Income tax provision	2,804			363			(i)	3,167
Net income and comprehensive income	$	9,893		$	1,088			$	10,981

(a)Under Canadian GAAP, the recoverable amount used to determine whether recognition of an impairment loss is required is the undiscounted future cash flows expected from its use and eventual disposition. Under IFRS the recoverable amount used in recognizing and measuring impairment is the higher of the asset’s fair value less costs to sell and its value in use. The recoverable amount was determined to be asset’s fair value less costs to sell, which was calculated based on the Company’s projected future cash flows. As a result, an impairment charge of $40.1 million relating to property, plant and equipment was recognized on January 1, 2010. The impairment related to the Company’s pipeline assets that are included within the terminals and pipeline segment. As a result of the impairment, depreciation expense relating to property, plant and equipment decreased by $3.3 million and $0.8 million for the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. As of December 31, 2010 and March 31, 2010, the total accumulated adjustment was to increase the deficit under IFRS by $36.7 million and $39.2 million, respectively.

(b)Under Canadian GAAP, the recoverable amount used to determine whether recognition of an impairment loss is required is the undiscounted future cash flows expected from its use and eventual disposition. Under IFRS the recoverable amount used in recognizing and measuring impairment is the higher of the asset’s fair value less costs to sell and its value in use. The recoverable amount was determined to be asset’s fair value less costs to sell, which was calculated based on the Company’s projected future cash flows. As a result, an impairment charge of $9.6 million relating to intangible assets was recognized on January 1, 2010. The impairment related to the Company’s customer relationship intangible assets. As a result of the impairment, amortization expense relating to intangible assets decreased by $2.5 million and $0.6 million for the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. As of December 31,

42

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

2010 and March 31, 2010, the total accumulated adjustment was to increase the deficit under IFRS by $7.1 million and $9.0 million, respectively.

(c)The Company’s activities give rise to decommissioning and environmental liabilities. On transition to IFRS, the Company elected to remeasure these liabilities in accordance with the provisions of IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”. Under IFRS, the liability was remeasured using a risk free rate as opposed to the credit adjusted rate under Canadian GAAP. As a result, on January 1, 2010, the Company increased its decommissioning and environmental liabilities by $19.3 million and property, plant and equipment by $12.8 million. In addition, following the acquisition of Battle River Terminal ULC, the Company increased its decommissioning and environmental liabilities and property, plant and equipment by an additional $1.9 million during the year ended December 31, 2010. As a result, the expense relating to the unwinding of the discount increased by $0.8 million and $0.2 million for the year ended December 31, 2010 and the three months ended March 31, 2010, respectively, and depreciation expense increased by $0.3 million and $0.1 million for the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. As of December 31, 2010 and March 31, 2010, the total adjustment to deficit under IFRS was to increase the deficit by $7.6 million and $6.8 million, respectively. In addition, as a result of the increase in property, plant and equipment and decommissioning liabilities, the Company reclassed an additional $0.6 million to assets held for sale and $0.8 million to liabilities related to assets held for sale.

(d)Under Canadian GAAP, capitalization of interest during the construction of a qualifying asset was an acceptable, but not mandatory, accounting policy. Accordingly, no interest was capitalized for qualifying assets. Under IFRS, capitalization of interest is required for qualifying assets that require a period of time to get them ready for their intended use. As of January 1, 2010, the carrying value of property, plant and equipment was increased by $0.3 million. Under IFRS, interest capitalized was $1.3 million and $0.3 million for the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. Additionally, depreciation expense increased by $0.1 million and $10,000 for the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. As of December 31, 2010 and March 31, 2010, the total adjustment to deficit under IFRS was to decrease the deficit by $1.5 million and $0.5 million, respectively.

(e)Under Canadian GAAP, the Company applied the corridor method of accounting for pension whereby gains and losses are recognized only if they exceed specified thresholds. Under IFRS, the Company recognizes actuarial gains and losses arising from the re-measurement of employee future benefit obligations in other comprehensive income as they arise. Accordingly, under IFRS, on transition the carrying value of the net liability for employee future benefit obligations increased by $2.8 million to recognize actuarial losses accumulated as at January 1, 2010, with a corresponding adjustment to deficit. As a result, amortization of the unrecognized loss under Canadian GAAP is no longer required, resulting in a decrease in expense of $0.2 million and $43,000 in the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. During the year ended December 31, 2010, the Company recognized an additional $0.6 million to the carrying value of the net liability for employee future benefit obligations.

(f)Under Canadian GAAP, the purchase price of an acquisition includes direct costs incurred by the acquirer, such as finder’s fees, advisors, legal, accounting, valuation and other professional or consulting fees. Under IFRS, these costs are expensed in the periods which they are incurred. The Company elected to apply the provisions of IFRS to all business combinations that occurred on or after January 1, 2010. The impact was to record additional expense of $2.4 million and $42,000 in the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. Additionally, as of December 31, 2010 and March 31, 2010, goodwill decreased by $2.4 million and $42,000, respectively.

43

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

(g)Under Canadian GAAP, capitalized computer software was included within property, plant and equipment. Under IFRS, capitalized computer software, not integral to plant and equipment, is classified as an intangible asset. On January 1, 2010, the Company reclassified $4.6 million from property, plant and equipment to intangible assets. In the year ended December 31, 2010 and the three months ended March 31, 2010, the Company incurred $2.0 million and $0.6 million respectively of capitalized computer software, which was reclassified from property, plant and equipment to intangible assets. In addition, in the year ended December 31, 2010 and three months ended March 31, 2010, the Company reclassified $1.7 million and $0.5 million, respectively from depreciation of property, plant and equipment to amortization of intangible assets. There was no net impact in the statement of income.

(h)Under IFRS, the Company is required to identify material components of assets within property, plant and equipment, and depreciate the components separately where the service life is different. Under Canadian GAAP, the Company had recognized certain components in prepaid expenses and other assets. On January 1, 2010, the Company reclassified $3.1 million from short term and long-term prepaid expenses and other assets to property, plant and equipment. In the year ended December 31, 2010 and the three months ended March 31, 2010, the Company reclassified $1.3 million and $0.3 million, respectively from short term and long-term prepaid expenses and other assets to property, plant and equipment. There was no net impact in the statement of income.

(i)Deferred tax liabilities have been adjusted to give effect to the impact of the adjustments above. In addition, under Canadian GAAP, deferred income tax relating to current assets or current liabilities must be classified as current. Under IFRS, it is not appropriate to classify deferred income tax balances as current, irrespective of the classification of the assets or liabilities to which the deferred income tax relates or the expected timing of reversal. Accordingly, current deferred income tax reported under Canadian GAAP has been reclassified as non-current under IFRS.

(j)Under Canadian GAAP, the Company classified certain gains and losses on the fair value movement of financial instruments in revenue. Under IFRS, these financial instruments do not meet the revenue recognition criteria. The impact was to reclassify $12.5 million and $0.3 million from revenue to a cost of sales in the year ended December 31, 2010 and the three months ended March 31, 2010, respectively. There was no net impact in the statement of income.

(k)The impact of the adjustments above was to decrease (increase) the deficit as follows:

		December 31, 2010			March 31, 2010			January 1, 2010
Impairment of property, plant and equipment	(a)	$	(36,745	)	$	(39,233	)	$	(40,062	)
Impairment of intangible assets	(b)	(7,123		)	(9,013		)	(9,643		)
Provisions	(c)	(7,610		)	(6,779		)	(6,514		)
Capitalized interest	(d)	1,488			538			282
Employee future benefits	(e)	(2,646		)	(2,775		)	(2,818		)
Business combinations	(f)	(2,401		)	(42		)	—
Tax impact of above adjustments	(i)	13,759			14,326			14,689
		$	(41,278	)	$	(42,978	)	$	(44,066	)

44

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

(iii)Adjustments to the statement of cash flows

The transition from Canadian GAAP to IFRS had no significant impact on cash flows generated by the company except that, under IFRS, cash flows relating to interest are classified as operating, investment or financing in a consistent manner each period. Under Canadian GAAP, cash flows relating to interest payments and interest income were classified as operating.

23   Additional IFRS information for the year ended December 31, 2010

The following IFRS disclosures relating to the year ended December 31, 2010 are considered material to the understanding of these interim financial statements.

(i)Property, plant and equipment

	Land & Buildings			Pipelines			Tanks			Rolling Stock			Plant & Equipment			Work in Progress			Total
Cost:
At January 1, 2010	$	70,487		$	88,862		$	180,096		$	116,826		$	177,118		$	58		$	633,447
Additions	2,278			1,342			11,956			19,068			14,781			13,082			62,507
Disposals	—			(398		)	(650		)	(3,987		)	127			—			(4,908		)
Additions through business acquisitions	1,438			—			49,429			37,698			36,641			395			125,601
Transfer to net investment in finance leases	—			—			(29,580		)	—			(2		)	—			(29,582		)
Transfer to assets held for sale	(4,196		)	(2,559		)	(12,713		)	(9		)	(17,286		)	(432		)	(37,195		)
Effect of movements in exchange rates	(1		)	—			(126		)	(1,192		)	(765		)	(15		)	(2,099		)
At December 31, 2010	$	70,006		$	87,247		$	198,412		$	168,404		$	210,614		$	13,088		$	747,771
Accumulated depreciation and impairment:
At January 1, 2010	$	4,301		$	10,998		$	8,640		$	16,210		$	22,991		$	—		$	63,140
Depreciation	3,733			7,299			10,166			22,352			17,962			—			61,512
Disposals	—			(493		)	(545		)	(1,143		)	54			—			(2,127		)
Transfer to net investment in finance leases	—			—			(462		)	—			—			—			(462		)
Transfer to assets held for sale	(178		)	(305		)	(984		)	(4		)	(2,498		)	—			(3,969		)
Effect of movements in exchange rates	(1		)	—			(7		)	(60		)	(10		)	—			(78		)
At December 31, 2010	$	7,855		$	17,499		$	16,808		$	37,355		$	38,499		$	—		$	118,016
Carrying amounts:
At January 1, 2010	$	66,186		$	77,864		$	171,456		$	100,616		$	154,127		$	58		$	570,307
At December 31, 2010	62,151			69,748			181,604			131,049			172,115			13,088			629,755

45

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

(ii)Intangible assets

	Brands		Customer relationships			Long-term contracts			Non-compete agreements			Technology		Software			Total
Cost:
At January 1, 2010	$	41,425	$	90,960		$	4,600		$	5,796		$	1,600	$	6,200		$	150,581
Additions	—		—			—			—			—		1,765			1,765
Acquisitions though business combinations	—		17,141			29,228			12,252			—		211			58,832
Effect of movements in exchange rates	—		(618		)	(1,125		)	(256		)	—		(14		)	(2,013		)
At December 31, 2010	$	41,425	$	107,483		$	32,703		$	17,792		$	1,600	$	8,162		$	209,165
Accumulated amortization and impairment:
At January 1, 2010	$	5,482	$	19,066		$	809		$	1,259		$	453	$	1,603		$	8,672
Amortization	4,031		14,900			2,608			4,687			430		1,722			28,378
Effect of movements in exchange rates	—		(53		)	(69		)	(86		)	—		(16		)	(224		)
At December 31, 2010	$	9,513	$	33,913		$	3,348		$	5,860		$	883	$	3,309		$	56,826
Carrying amounts:
At January 1, 2010	$	35,943	$	71,894		$	3,791		$	4,537		$	1,147	$	4,597		$	121,909
At December 31, 2010	31,912		73,570			29,355			11,932			717		4,853			152,339

(iii)Compensation of key management

Key management includes the Company’s directors, executive officers, business unit leaders and other non-business unit senior vice presidents. Compensation awarded to key management was:

	Year ended December 31, 2010
Salaries and short-term employee benefits	$	3,971
Post-employment benefits	809
Stock based compensation	2,650
	$	7,430

(iv)Employee benefits

	Year ended December 31, 2010
Salaries and wages	$	94,776
Post-employment benefits	4,154
Stock based compensation	4,629
Termination benefits	1,303
	$	104,862

46

Gibson Energy Holding ULC

Notes to Condensed Consolidated Interim Financial Statements

(Unaudited)

(tabular amounts in thousands of Canadian dollars, except where noted)

(iv)Depreciation and amortization

	Year ended December 31, 2010
Depreciation of property, plant and equipment	$	61,512
Amortization of intangible assets	28,378
	$	89,890

Depreciation of property, plant and equipment and amortization of intangible assets have been expensed as follows:

	Year ended December 31, 2010
Cost of sales	$	87,125
General and administrative	2,765
	$	89,890

24Subsequent Events

On April 27, 2011, the Company announced that concurrent with the consummation of an Initial Public Offering (the “Offering”), Gibson Energy Inc., Gibson Energy Holding ULC and 1441682 Alberta Ltd. will amalgamate into one entity, with the surviving entity being Gibson Energy Inc. (the “Reorganization”). After the Reorganization, the common shares of Gibson Energy Inc. will be the common shares offered in the Offering. The Reorganization is a common control transaction whereby Gibson Energy Inc. will be accounted for using continuity of interest and, as such, Gibson Energy Inc. is considered a continuity of Gibson Energy Holding ULC.

Concurrently with the Offering, the Company intends to enter into a series of transactions intended to refinance the Company’s existing indebtedness (the “Refinancing”). As part of the Refinancing, Gibson Energy ULC, a wholly owned subsidiary of Gibson Energy Holding ULC, expects to enter into a new senior secured Credit Facility (the “New Credit Facility”) consisting of a senior secured first lien term loan facility in an aggregate principal amount of up to U.S.$700.0 million, with a term of seven years (the “Term Loan”), and a senior secured first lien revolving credit facility of up to U.S.$250.0 million, with a term of five years. The Company, and all of the existing and future wholly-owned subsidiaries of Gibson Energy ULC, subject to certain exceptions, will guarantee the obligations under the New Credit Facility.

47

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

The following information should be read in conjunction with our unaudited condensed consolidated financial statements for the three months ended March 31, 2011 and 2010, which were prepared under International Financial Reporting Standards (“IFRS”) and our audited consolidated financial statements and related notes for the years ended December 31, 2010 and 2009, the period from December 13, 2008 to December 31, 2008, and the period from January 1, 2008 to December 12, 2008, which were prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). This is our first reporting period using IFRS accounting policies. In accordance with IFRS 1, our transition date to IFRS was January 1, 2010 and therefore the comparative information for 2010 has been prepared in accordance with our IFRS accounting policies. The 2009 financial information contained within this Management Discussion and Analysis has been prepared following Canadian GAAP and has not been re-presented. For a discussion of the differences between IFRS and Canadian GAAP applicable to the Company, see note 23 to our unaudited condensed consolidated financial statements for the three months ended March 31, 2011 and 2010.

The unaudited condensed consolidated financial statements referred to above include all adjustments of a normal recurring nature necessary for the fair statement of the Company’s financial position as of March 31, 2011, its results of operations for the three months ended March 31, 2011 and 2010, and its cash flows for the three months ended March 31, 2011 and 2010. The unaudited condensed consolidated financial statements do not include all disclosures required by IFRS or Canadian GAAP and should be read in conjunction with the annual audited consolidated financial statements and related notes. The results for the interim periods are not necessarily indicative of the results to be expected for any future period or for the fiscal year ending December 31, 2011. Amounts are stated in Canadian dollars unless otherwise noted.

In addition, the statements in the discussion and analysis regarding industry outlook, our expectations regarding the performance of our business and the forward-looking statements are subject to numerous risks and uncertainties, including, but not limited to, the risks and uncertainties described in “Risk factors” and “Cautionary note regarding forward-looking statements” included in our annual report on Form 20-F, as filed with the Securities and Exchange Commission (“SEC”) on April 29, 2011. Our actual results may differ materially from those contained in or implied by any forward-looking statements.

EXECUTIVE OVERVIEW

We are one of the largest independent midstream energy companies in Canada and a major participant in the crude oil transportation business in the United States and are engaged in the movement, storage, blending, processing, marketing, and distribution of crude oil, condensate, natural gas liquids, and refined products.  We transport hydrocarbons by utilizing our integrated network of terminals, pipelines, storage tanks, and truck fleet located throughout western Canada and the United States.  We are also involved in the processing, blending and marketing of hydrocarbons and are the second largest retail propane distribution company in Canada.  Our integrated operations allow us to participate across the full midstream energy value chain, from the hydrocarbon producing regions in Canada and the United States, through our strategically located terminals in Hardisty and Edmonton, Alberta and injection stations in the United States, to the refineries of North America via major pipelines.

We have provided market access to leading oil and gas participants in western Canada for the last 58 years. We have grown our business by diversifying our service offerings to meet customers’ needs and by expanding geographically. Most recently, we expanded our service offerings to key hydrocarbon producing regions throughout the United States to position us as a North American midstream energy company.

We are a wholly owned subsidiary of R/C Guitar Cooperative of U.A., a Dutch co-op owned by investment funds affiliated with Riverstone LLC (“Riverstone”).

Our five integrated business segments can be broken down as follows: (1) terminals and pipelines, (2) truck transportation, (3) propane and NGL marketing and distribution, (4) processing and wellsite fluids and (5) marketing. We believe our competitive advantage is driven by our geographic presence in some of the most hydrocarbon-rich basins in the world, our footholds in strategic market hubs, our positioning which enables us to capture value throughout the energy value chain, our diversified, integrated, synergistic service offerings, our proven track record of sourcing and successfully executing internal growth projects, our proven track record of sourcing, executing and successfully integrating business acquisitions, our leading health, safety, security and environmental record, our experienced management with a proven history of profitable operations and strong industry reputation and our high quality, energy-focused investor. We are continuously focused on improving our operations across all segments by lowering costs, utilizing our integrated asset base to capture inter-segment

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synergies and expanding our network of assets, as well as increasing our margins by providing additional value-adding services along the midstream energy chain.

Highlights

The key highlights of the three months ended March 31, 2011, compared to the three months ended March 31, 2010, were:

·Revenue increased 19% and cost of sales increased 18%, primarily due to increased activity and global commodity price increases;

·Segment profit increased by 55%, with increases across all of our operating segments;

·On January 7, 2011, we completed the disposition of our Edmonton North Terminal to Pembina Midstream Limited Partnership for consideration of approximately $54.3 million, realizing a gain on the sale of $20.4 million. The terminal was a remotely operated facility located in Edmonton, Alberta, with a capacity of 310,000 barrels. As part of the consideration received, we secured important pipeline assets and connections that will provide access to crude oil streams within the Edmonton area, thereby allowing us to expand and grow our Edmonton South Terminal; and

·Net income was $40.1 million in the three months ended March 31, 2011 compared to net income of $11.0 million in the three months ended March 31, 2010. The increase was primarily due to the increase in segment profit and also due to the gain on sale of our Edmonton North Terminal.

On April 27, 2011, our affiliate, Gibson Energy Inc., filed a preliminary prospectus with the securities regulatory authority in each of the provinces and territories of Canada, whereby it intends to complete an initial public offering of its common shares (the “Offering”). Concurrent with the Offering, we intend to enter into a series of transactions intended to refinance our existing indebtedness (the “Refinancing”), whereby we expect to enter into a new senior secured first lien term loan facility in an aggregate principal amount of up to U.S.$700.0 million, with a term of seven years (the “Term Loan”), and a revolving credit facility of up to U.S.$250.0 million, with a term of five years (the “Revolving Credit Facility”).  As part of the transactions, Gibson Energy Holding ULC, Gibson Energy Inc. and 1441682 Alberta Ltd. will amalgamate into one entity, with the surviving entity being Gibson Energy Inc. (the “Reorganization”). The Reorganization is a common control transaction whereby Gibson Energy Inc. will be accounted for using continuity of interest and, as such, Gibson Energy Inc. will be considered a continuity of Gibson Energy Holding ULC. We intend to use the proceeds from the Offering and the Refinancing to refinance our outstanding First Lien Senior Secured Notes issued on May 27, 2009 in an aggregate principal amount of U.S.$560.0 million (“First Lien Notes”) and our Unsecured Senior Notes issued on January 19, 2010 in an aggregate principal amount of U.S.$200.0 million (“Senior Notes”, and together with the First Lien Notes , the “Notes”) through either an offer to purchase for cash any and all of the outstanding Notes or through satisfaction and discharge, defeasance or a manner otherwise permitted under the respective indentures governing the Notes, to repay any amounts outstanding under our asset backed credit facility of up to U.S.$200.0 million (“Credit Facility”) and for general corporate purposes.

Trends affecting our business

In accordance with our long-range strategic plan, we are continuously evaluating organic growth opportunities and potential acquisitions of transportation, retail propane distribution, gathering, terminalling or storage and other complementary midstream businesses. Some of the key industry trends that are currently affecting our business and prospects are:

·Increased activity levels are forecasted to continue in the Bakken, Cardium, Viking, Eagle Ford, and Niobrara areas stemming from increased drilling budgets proposed by industry leaders. We believe this should generate increased demand for the services we provide;

·The unrest in the Middle East that is currently occurring is underscoring the importance of domestic oil production to the North American market. We believe this should result in an increased focus on development of North American supply and generate further drilling activity and production levels domestically;

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·Technology advancements within the drilling and fracturing process are providing production companies new opportunities to increase production levels from wells that were previously uneconomic and to bring on production from areas that were previously unable to economically produce crude oil, such as tight shale plays;

·Increased production levels and increased crude oil prices have increased demand for all facets of the midstream energy value chain including storage, transportation, distribution, processing and refining, all of which are activities in which we participate; and

·In the first nine months of 2010, heavy to light crude oil pricing differentials were at historically low levels. During the latter part of 2010 and in the three months ended March 31, 2011, there has been a widening of these differentials more in line with longer term averages. This creates incremental margin opportunities in multiple areas of our operations.

Longer-term outlook

Our longer-term outlook, spanning three to five years or more, is influenced by many factors affecting the North American midstream energy sector.  Some of the more significant trends and developments relating to crude oil include:

·New technology and drilling methodology being deployed towards conventional and unconventional production within our operating areas;

·Uncertainty and volatility relating to crude oil prices and price differentials between crude oil streams and blending agents;

·Increased crude oil production on shore in North America, including from the Canadian oil sands; and

·Expansion of the midstream infrastructure in North America to handle increased production and expansion of capacity in the U.S. refining complex to handle heavier crude oil from the Western Canadian Sedimentary Basin (“WCSB”).

We believe the collective impact of these trends and developments, many of which are beyond our control, will result in an increasingly volatile crude oil market that is subject to more frequent short-term swings in market prices and grade differentials and shifts in market structure.

Acquisitions and internal growth projects

The following table summarizes our capital expenditures for internal growth projects, acquisitions and upgrade and replacement capital (in thousands):

	Three months ended March 31,
	2011		2010
Internal growth projects	$	14,959	$	6,801
Acquisitions	—		24,695
Upgrade and replacement capital(1)	8,468		1,736
	$	23,427	$	33,232

(1)Upgrade capital above includes improvement projects that extend the physical life of an asset, while replacement capital includes purchases that replace existing assets as necessary to maintain current service levels or replace assets that no longer have a useful economic life.

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Total capital expenditures for internal growth projects and upgrade and replacement capital were $23.4 million and $8.5 million in the three months ended March 31, 2011 and 2010, respectively. In the three months ended March 31, 2011 and 2010, $21.9 million and $8.0 million, respectively, were included as additions to property, plant and equipment and $1.5 million and $0.5 million, respectively, were included as additions to intangible assets.

Internal growth projects

In the three months ended March 31, 2011, our internal growth projects included: the continued expansion of our Canwest Propane truck fleet and tankage; the expansion of our truck transportation fleet; and the construction of new tankage and pipeline connections at both our Hardisty Terminal and Edmonton South Terminal.

The following table summarizes our key projects undertaken in the three months ended March 31, 2011 and 2010
(in thousands):

	Three months ended March 31,
	2011		2010
Canwest fleet and tank expansion(1)	$	987	$	1,212
Truck transportation fleet expansion(2)	4,956		—
Hardisty storage tank construction(3)	974		—
Hardisty West Terminal project(4)	325		—
Hardisty line 4 (MM150) connection(5)	546		—
Hardisty Cold Lake pipeline connection(6)	4,096		—
Southern Lights connection at Edmonton(7)	338		—
Pipeline assets received as part of the sale of the Edmonton North Terminal(8)	900		—
Moose Jaw refinery capacity expansion(9)	39		975
Edmonton South Terminal storage tank construction(10)	—		1,155
Purchase of land(11)	—		1,601
Rail loading rack at Edmonton(12)	—		474
Other growth projects(13)	1,798		1,384
Total	$	14,959	$	6,801

(1)Represents the ongoing addition of trucks, tank capacity and generators to meet growing demand in key market areas.

(2)Represents the ongoing addition of rolling stock to meet demand growth in key market areas, including the United States.

(3)Represents capital spent to build a tank at our Hardisty Terminal. We have entered into an agreement whereby, on completion, the tank will be leased to a customer on a long-term minimum fee basis.

(4)Represents capital spent to date to build and operate four 300,000 barrel tanks at our Hardisty Terminal (“Hardisty West Terminal”). The total cost of construction is estimated to be approximately $88.0 million, with our share being 50% of the total.

(5)Represents capital spent to build a connection from Enbridge line 4 at our Hardisty Terminal. The total cost of the construction is estimated to be $9.5 million.

(6)Represents capital spent to build a connection to the Cold Lake pipeline system at our Hardisty Terminal. The total cost of the construction is estimated to be $5.4 million.

(7)Represents capital spent to connect the Edmonton South Terminal to the Southern Lights pipeline. The total cost of the construction is estimated to be $6.6 million.

(8)Represents important pipeline assets received as part of the sale of the Edmonton North Terminal that will provide access to crude oil streams within the Edmonton area, thereby allowing us to expand and grow our Edmonton South Terminal.

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(9)Represents expenditures incurred in the expansion of capacity and the building of a new tank at the Moose Jaw Refinery.

(10)Represents capital spent to build a tank at our Edmonton South Terminal which went into service in 2010. Total spend on the tank was $3.1 million.

(11)Represents the purchase of land in Calgary, Alberta, for our retail propane business.

(12)Represents capital spent to expand our rail loading facilities at our Edmonton South Terminal.

(13)Represents a number of smaller projects similar in nature to, but smaller in scope than, those discussed above.

Acquisitions

In the three months ended March 31, 2011, we did not complete any acquisitions. In the three months ended March 31, 2010, we completed the acquisition of Johnstone Tank Trucking Ltd. (“Johnstone”) for aggregate consideration of $21.3 million, effective January 31, 2010, and of Aarcam Propane & Construction Heat Ltd. (“Aarcam”) for aggregate consideration of $3.4 million, effective February 1, 2010. The acquired businesses impacted our results of operations commencing on the effective date of each acquisition.

Seasonality

We believe that seasonality does not have a material impact on our combined operations and segments. However, certain of our individual segments are impacted by seasonality. Generally, our results are impacted in the second quarter due to road bans and other restrictions which impact overall activity levels in the WCSB, and therefore negatively impact our trucking and wellsite fluids business in Canada.

Our processing and wellsite fluids segment is impacted by seasonality because the asphalt industry in Canada is affected by the impact that weather conditions have on road construction schedules. Refineries produce liquid asphalt year round, but asphalt demand peaks during the summer months when most of the road construction activity in Canada takes place. Demand for wellsite fluids is dependent on overall well drilling activity, with drilling activity normally the busiest in the winter months. As a result, our processing and wellsite fluids segment’s sales of liquid asphalt peak in the summer and sales of wellsite fluids peak in the winter.

Our propane and NGL marketing and distribution segment is characterized by a high degree of seasonality with much of the seasonality driven by the impact of weather on the need for heating and the amount of propane required to produce power for oil and gas related applications. Therefore, volumes are low during the summer months relative to the winter months. Operating profits are also considerably lower during the summer months. Most of the annual segment profits are earned from October to March each year.

ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS

This is our first reporting period using our IFRS accounting policies. In accordance with IFRS 1, our transition date to IFRS was January 1, 2010 and therefore the comparative information for 2010 has been prepared in accordance with our IFRS accounting policies. The 2009 financial information contained within this Management Discussion and Analysis has been prepared following Canadian GAAP and has not been re-presented.

ACCOUNTING POLICIES

As discussed in Note 2 to our unaudited condensed consolidated financial statements for the three months ended March 31, 2011, we will adopt IFRS for the first time in our financial statements for the year ended December 31, 2011, which will include comparative financial statements for the year ended December 31, 2010. IFRS 1 “First-time Adoption of International Financial Reporting Standards”, requires that an entity develop accounting policies based on standards and related interpretations effective at the reporting date of its first annual IFRS financial statements, which in our case will be December 31, 2011. IFRS 1 also requires that those policies be applied as of the date of transition to IFRS, which in our case is January 1, 2010, and throughout all period presented in the first IFRS financial statements. The unaudited condensed consolidated financial statements as of March 31, 2011 and the three months ended March 31, 2011 and 2010, have been

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prepared in accordance with those International Accounting Standard Board (“IASB”) standards and International Financial Reporting Interpretations Committee (“IFRIC”) interpretations issued and effective as of May 12, 2011, the date the Board of Directors approved the unaudited interim condensed consolidated financial statements for issuance. The IASB and IFRIC interpretations that will be applicable at December 31, 2011, including those that will be applicable on an optional basis , are not known with certainty at the time of preparing the unaudited interim condensed consolidated financial statements. As a result, the accounting policies used to prepare this financial information are subject to change up to the reporting date of our first IFRS annual financial statements. In this regard, before the first annual financial statements prepared under IFRS are complete, and such financial statements are audited, the IFRS financial information is subject to change.

Our interim consolidated financial statements for the three months ended March 31, 2011 provide the following reconciliations from Canadian GAAP to IFRS:

·Balance sheet as at January 1, 2010;

·Balance sheet as at March 31, 2010;

·Balance sheet as at December 31, 2010;

·Statement of  income for the three months ended March 31, 2010; and

·Statement of income for the year ended December 31, 2010.

The following is a summary of the significant impacts on our results for the three months ended March 31, 2010 and the year ended December 31, 2010.

Impairment testing. Under IFRS, the recoverable amount used in recognizing and measuring an impairment is the greater of the asset’s fair value less costs to sell and its value in use. Under Canadian GAAP, the recoverable amount used to determine whether recognition of an impairment loss is required is the undiscounted future cash flows expected from its use and eventual disposition.  As a result of the change in approach, on January 1, 2010, we recognized an impairment charge of $40.1 million relating to property, plant and equipment and of $9.6 million relating to intangible assets. As a result of this impairment charge, depreciation and amortization expense decreased by $1.5 million and $5.8 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Asset retirement obligations. On transition to IFRS, we elected to remeasure asset retirement obligations in accordance with the provisions of International Accounting Standard 37 “Provisions, Contingent Liabilities and Contingent Assets”. Under IFRS, the liability is remeasured at each reporting date using the current risk free interest rate as opposed to the credit adjusted rate used under Canadian GAAP. As a result, on January 1, 2010, we increased property, plant and equipment by $12.8 million and the asset retirement obligations liability by $19.3 million, with a net impact to deficit of $6.5 million. In addition, as a result of acquisitions during the year, we remeasured our asset retirement obligations on the acquisition dates, which resulted in an additional increase in property, plant and equipment and asset retirement obligations liability of $1.9 million. As a result, the expense relating to the unwinding of the discount increased by $0.2 million and $0.8 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively and depreciation of property, plant and equipment increased by $0.1 million and $0.3 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Capitalized Interest. Under Canadian GAAP, capitalization of interest during the construction of a qualifying asset was an acceptable, but not mandatory, accounting policy. We chose not to capitalize interest for qualifying assets. Under IFRS, capitalization of interest is required for qualifying assets under construction prior to the time they are ready for use. As a result, on January 1, 2010, the carrying value of property, plant and equipment was increased by $0.3 million. In addition, under IFRS, interest capitalized was $0.3 million and $1.3 million during the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.  As a result, depreciation of property, plant and equipment increased by $10,000 and $0.1 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Employee benefit plans. Under IFRS, we elected to recognize actuarial gains and losses arising from the re-measurement of employee future benefit obligations in other comprehensive income as they arise. Under Canadian GAAP, we applied the corridor method of accounting whereby gains and losses are recognized only if they exceed specified thresholds. Accordingly, under IFRS, the carrying value of the net liability for employee future benefit obligations will increase by approximately $2.8 million to recognize actuarial losses accumulated on the transition date of January 1, 2010. In addition, at December 31, 2010, we recognized an additional $0.6 million to the carrying value of the net liability for employee future benefit obligations. As a result, amortization of the unrecognized loss under Canadian GAAP is no longer required, resulting

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in a decrease in general and administrative expense of $43,000 and $0.2 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively.

Capitalized software. Under Canadian GAAP, capitalized computer software was included within property, plant and equipment. Under IFRS, capitalized computer software, not integral to plant and equipment, is classified as an intangible asset. On January 1, 2010, we reclassified approximately $4.6 million from property, plant and equipment to intangible assets. In the three months ended March 31, 2011 and the year ended December 31, 2010, we incurred approximately $0.6 million and $2.0 million, respectively, of capitalized computer software, which was reclassified from property, plant and equipment to intangible assets. There was no net impact in the statement of income.

Business Combinations. Under Canadian GAAP, the purchase price of an acquisition includes direct costs incurred by the acquirer, such as finder’s fees, advisors, legal, accounting, valuation and other professional or consulting fees. Under IFRS, these costs associated with business acquisitions are expensed in the period they are incurred. We elected to apply IFRS to all business combinations that occurred on or after January 1, 2010. The impact was additional general and administrative expense of $42,000 and $2.4 million for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively, with a corresponding decrease in goodwill.

Property, plant and equipment. Under IFRS, we are required to identify material components of assets within property, plant and equipment, and depreciate the components based on the estimated service life of the components. Under Canadian GAAP, we had recognized certain components in prepaid expenses and other assets. On January 1, 2010, we reclassified $3.1 million from short term and long-term prepaid expenses and other assets to property, plant and equipment. In the three months ended March 31, 2010 and the year ended December 31, 2010, we reclassified $0.3 million and $1.2 million, respectively, from short term and long-term prepaid expenses and other assets to property, plant and equipment. As a result of the reclassifications, there was no net impact in the statement of income.

Revenue. Under Canadian GAAP, we classified certain realized and unrealized gains (losses) on financial instruments in revenue. Under IFRS, these financial instruments do not meet the revenue recognition criteria. The impact was to reclassify $0.3 million and $12.5 million of losses from revenue to cost of sales for the three months ended March 31, 2010 and the year ended December 31, 2010, respectively. There was no net impact in the statement of income.

Income taxes. We have evaluated the differences in guidance between International Accounting Standard 12, “Income Taxes” and the relevant Canadian GAAP requirements and concluded that, other than the tax effecting the adjustments, the impact will be minimal. In addition, under Canadian GAAP, deferred income tax relating to current assets or current liabilities were classified as current. Under IFRS, it is not appropriate to classify deferred income tax balances as current, irrespective of the classification of the assets or liabilities to which the deferred income tax relates to or the expected timing of reversal. Accordingly, current deferred income tax reported under Canadian GAAP will be reclassified as non-current under IFRS.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements in conformity with IFRS requires management to make estimates and assumptions. Predicting future events is inherently an imprecise activity and, as such, requires the use of judgment. Actual results may vary from estimates in amounts that may be material to the financial statements. An accounting policy is deemed to be critical if it requires an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time the estimate is made, and if different estimates that reasonably could have been used, or changes in the accounting estimates that are reasonably likely to occur periodically, could materially impact our consolidated financial statements. Our critical accounting policies and estimates are discussed in our annual report on Form 20-F filed with the SEC on April 29, 2011. The following discussion highlights significant changes to our critical accounting policies and estimates from those disclosed in our annual report on Form 20-F for the year ended December 31, 2010, as a result of the adoption of IFRS.

Asset impairments

For impairment testing, the assessment of facts and circumstances is a subjective process that often involves a number of estimates and is subject to interpretation. Also, the testing of an asset or cash generating unit (“CGU”) for impairment, as well as the assessment of potential impairment reversals, requires that we estimate an asset’s or CGU’s recoverable amount. The estimate of a recoverable amount requires a number of assumptions and estimates, including outlook for global or

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regional market supply-and-demand conditions, future commodity prices, the effects of inflation on operating expenses and discount rates. These assumptions and estimates are subject to change as new information becomes available and changes in any of the assumptions could result in an impairment of an asset’s or CGU’s carrying value.

Decommissioning and environmental remediation liabilities

Since the discount rate used to estimate our decommissioning and environmental remediation liabilities is updated each reporting period under IFRS, changes in the risk-free rate can change the amount of the liability, and these changes could potentially be material in the future.

FUTURE CHANGES IN ACCOUNTING POLICIES

IFRS accounting policies

Our IFRS financial statements for the year ending December 31, 2011 must use the standards that are in effect on December 31, 2011, and therefore our financial statements under IFRS for the three month period ended March 31, 2011 are subject to change. Changes to the accounting policies used may result in material changes to our reported financial position, results of operations and cash flows.

Financial instruments

The IASBintends to replace International Accounting Standard 39, “Financial Instruments: Recognition and Measurement” (“IAS 39”) with IFRS 9, “Financial instruments” (“IFRS 9”). IFRS 9 will be published in three phases, of which the first phase has been published.

The first phase addresses the accounting for financial assets and financial liabilities. The second phase will address the impairment of financial instruments, and the third phase will address hedge accounting.

For financial assets, IFRS 9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, and replaces the multiple rules in IAS 39. The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment methods in IAS 39. For financial liabilities, although the classification criteria for financial liabilities will not change under IFRS 9, the approach to the fair value option for financial liabilities may require different accounting for changes to the fair value of a financial liability as a result of changes to an entity’s own credit risk.

IFRS 9 is effective for annual periods beginning on or after January 1, 2013 with different transitional arrangements depending on the date of initial application. We are currently evaluating the impact of adopting IFRS 9 on our consolidated financial statements.

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RESULTS OF OPERATIONS

The following is a discussion of our results of operations for the three months ended March 31, 2011 and 2010, and the following table sets forth our consolidated statements of operations for those periods (in thousands):

	Three months ended
	March 31, 2011			March 31, 2010
Revenue	$	1,148,017		$	964,529
Cost of sales	1,104,199			938,252
Gross profit	43,818			26,277
General and administrative	7,374			8,070
Gain on Sale of Edmonton North Terminal	(20,370		)	—
Other operating expenses (income)	1,176			535
Income from operating activities	55,638			17,672
Loss from investment in associates	86			504
Interest expense	24,705			24,036
Interest income	(58		)	(216		)
Foreign exchange gain on long-term debt	(17,328		)	(20,800		)
Income before income taxes	48,233			14,148
Income tax provision	8,102			3,167
Net income	$	40,131		$	10,981

Our senior management evaluates segment performance based on a variety of measures depending on the particular segment being evaluated, including profit, volumes, operating expenses, profit per barrel and upgrade and replacement capital requirements. We define segment profit as revenues minus (i) cost of sales and (ii) operating expenses. Revenues presented by segment in the table below include inter-segment revenue, as this is considered more indicative of the level of each segment’s activity. Profit by segments excludes depreciation, amortization, accretion, impairment charges and stock based compensation, as we look at each period’s earnings before non-cash depreciation, amortization and stock based compensation as one of our important measures of segment performance. We have also excluded the gain on the sale of our Edmonton North Terminal from segment profit since it is a non-recurring gain. The terminal was part of our marketing segment.

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Revenue and profit by segment for the three months ended March 31, 2011 and 2010 were as follows:

	Three months ended March 31,
	2011			2010
	(in thousands)
Segment revenue
Terminals and pipelines	$	222,825		$	282,167
Truck transportation	107,618			66,012
Propane and NGL marketing and distribution	268,972			174,116
Processing and wellsite fluids	119,359			120,521
Marketing	815,780			870,724
Total segment revenue	1,534,554			1,513,540
Revenue—inter-segmental	(386,537		)	(549,011		)
Total revenue—external	1,148,017			964,529
Segment profit
Terminals and pipelines	16,736			8,382
Truck transportation	16,236			9,622
Propane and NGL marketing and distribution	17,548			13,175
Processing and wellsite fluids	11,128			9,143
Marketing	4,826			2,634
Total segment profit	66,474			42,956
General and administrative	5,982			6,237
Depreciation and amortization	23,806			18,675
Stock based compensation	621			1,150
Foreign exchange gain	(16,445		)	(21,074		)
Gain on sale of Edmonton North Terminal	(20,370		)	—
Interest expense, net	24,647			23,820
Income before income tax	48,233			14,148
Income tax expense	8,102			3,167
Net income	$	40,131		$	10,981

The exclusion of depreciation and amortization expense could be viewed as limiting the usefulness of segment profit as a performance measure because it does not take into account in current periods the implied reduction in value of our capital assets (such as rolling stock, crude oil pipelines and facilities) caused by aging and wear and tear. Repair and maintenance expenditures that do not extend the useful life, improve the efficiency or expand the operating capacity of the asset are charged to operating expense as incurred.

Our segment analysis involves an element of judgment relating to the allocations between segments. Inter-segment sales and cost of sales and operating expenses are eliminated on consolidation. Transactions between segments and within segments are valued at prevailing market rates. We believe that the estimates with respect to these allocations and rates are reasonable.

Terminals and pipelines

The following tables set forth our operating results from our terminals and pipelines segment:

	Three months ended March 31,
Volumes (barrels in thousands)	2011	2010
Hardisty Terminal	21,271	14,570
Edmonton South Terminal	3,780	3,759
Total terminals	25,051	18,329
Custom terminals	2,329	3,292
Injection stations	8,181	—
Bellshill	451	484
Provost	1,746	1,718
Total pipelines	2,197	2,202

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	Three months ended March 31,
	2011		2010
	(in thousands)
Revenues	$	222,825	$	282,167
Cost of sales	199,573		267,546
Operating expenses and other	6,516		6,239
Segment profit	$	16,736	$	8,382

Three months ended March 31, 2011 and 2010.

Volumes, revenues and cost of sales.

Hardisty Terminal volumes increased 46% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, as a result of increased volumes from the Athabasca pipeline and from other pipeline sources and also due to increased volumes through the additional tanks that were acquired as part of our acquisition of the remaining 75% interest in Battle River Terminal ULC (“BRT”). Overall revenues increased by $5.5 million in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. The increase in revenue was due to both the increase in volume and the impact of additional revenue from customers who have dedicated tank usage, which are not based on volume.

Edmonton South Terminal volumes remained relatively stable, increasing by 1% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. Revenues at the Edmonton South Terminal increased by $0.1 million in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, as a result of the increase in volumes. Revenue per barrel remained relatively stable in the three months ended March 31, 2011 compared to the three months ended March 31, 2010.

Custom terminal volumes decreased 29% in the three months ended March 31, 2011, compared to the three months ended March 31, 2010, as a result of a decrease in the trucked in volume at our Edmonton South Terminal. As a result of the decrease in volumes, revenues decreased by approximately $66.3 million in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, which also resulted in a corresponding decrease in cost of sales.

As part of the acquisition of Taylor Logistics LLC and substantially all of the assets of Taylor Propane Gas Inc. (collectively, “Taylor”) on May 14, 2010, we acquired 71 injection stations located in the United States, primarily in Louisiana, Texas, Oklahoma, Wyoming, Montana and North Dakota and a pipeline located in Texas. Revenue is charged based on volumes that run through the injection stations and the pipeline and was $1.0 million for the three months ended March 31, 2011.

Volumes for our Bellshill pipeline were 7% lower in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, due to a natural decline in receipts from the oil production batteries that produce into the pipeline. However, revenue increased by $0.1 million in the three months ended March 31, 2011 compared to the three months ended March 31, 2010 as a result of an increase in tariffs which more than offset the decrease in volumes. The tariff increase resulted in a 30% increase in revenue per barrel.

Volumes for our Provost pipeline increased by 2% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, largely as a result of a new oil production battery coming on stream in the third quarter of 2010. The increased volumes and tariff increases led to revenue increasing by $0.2 million in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. In addition, an increase in tariffs resulted in a 7% increase in revenue per barrel.

Operating expenses and other.  Overall operating expenses and other costs increased by $0.3 million, or 4%. The increase was largely related to the additional operating costs as a result of the Taylor acquisition.  Other operating costs remained relatively stable.

Segment profit.  Overall, segment profit in the three months ended March 31, 2011 increased by $8.4 million, or 100%, compared to the three months ended March 31, 2010. The primary reason for the increase was due to increased activity

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through our Hardisty Terminal, largely as a result of the BRT acquisition, and increased profits being generated from our custom terminal operations.

Truck transportation

The following tables set forth our operating results from our truck transportation segment:

	Three months ended March 31,
Volumes (barrels in thousands)	2011	2010
Barrels hauled	35,719	25,902

	Three months ended March 31,
	2011		2010
	(in thousands)
Revenues	$	107,618	$	66,012
Cost of sales	75,425		43,864
	32,193		22,148
Operating expenses and other	15,957		12,526
Segment profit	$	16,236	$	9,622

Three months ended March 31, 2011 and 2010.

Volumes, revenues and cost of sales.

For the three months ended March 31, 2011, barrels hauled increased by 38% compared to the three months ended March 31, 2010, due mainly to the impact of the acquisition of Taylor, which occurred on May 14, 2010 and to a lesser extent the full quarter impact of the acquisition of Johnstone, which occurred on January 31, 2010.  In addition, hauling volumes, particularly for propane, increased due to strong demand from a major customer.  However, this was offset by a decrease in petroleum coke hauling that experienced strong demand in the three months ended March 31, 2010 due to an overall increase in demand in the industry for the product.

Revenues increased by 63% in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The increase was mainly as a result of the increased volumes largely driven by the acquisitions of Taylor and Johnstone but also due to an increase in fuel surcharge revenue, rate increases and an increase in the number of long hauls.

Cost of sales is primarily comprised of payments to owner-operators and lease operators. Cost of sales in the three months ended March 31, 2011 increased 72%, as compared to the three months ended March 31, 2010. The increase was largely driven by the increase in revenue with the additional increase due to a higher cost of sales for Taylor trucking.

Operating expenses and other.  Overall operating expenses and other costs increased by $3.4 million, or 27%, in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, mainly due to the impact of additional costs related to the Taylor and Johnstone acquisitions. The remaining operating expenses remained relatively stable for the three months ended March 31, 2011 compared to the three months ended March 31, 2010.

Segment profit.  Segment profit increased as a result of the increase in revenues, mainly driven by the impact of the Taylor acquisition and an increase in activity levels, which increased overall margins.

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Propane and NGL marketing and distribution

The following tables set forth operating results from our propane and NGL marketing and distribution segment:

	Three months ended March 31,
Volumes	2011	2010
Sales volumes—retail (gallons in thousands)
Residential	2,177	1,666
Oil and gas	13,577	10,726
Commercial and industrial	7,516	5,225
Automotive	1,257	1,360
Other	1,422	1,245
	25,949	20,222
Sales volumes—wholesale
Propane distribution (gallons in thousands)	76,053	62,079
NGL Marketing (barrels in thousands)
Propane	—	41
Butane	561	253
Condensate	250	297
Taylor	624	—
	1,435	591

	Three months ended March 31,
	2011		2010
	(in thousands)
Revenues
Retail
Propane	$	53,127	$	41,930
Other	646		559
Total retail	53,773		42,489
Wholesale
Propane distribution	99,125		83,232
NGL Marketing	112,073		45,204
Total wholesale	211,198		128,436
Other	4,001		3,191
Total revenues	268,972		174,116
Cost of sales
Retail
Propane	37,691		29,800
Other	508		430
Total retail	38,199		30,230
Wholesale
Propane distribution	93,918		76,773
NGL Marketing	107,044		43,244
Total wholesale	200,962		120,017
Total cost of sales	239,161		150,247
	29,811		23,869
Operating expenses and other	12,263		10,694
Segment profit	$	17,548	$	13,175

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Three months ended March 31, 2011 and 2010.

Volumes, revenues and cost of sales.

Retail volumes increased 28% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, largely as a result of increased volumes in the oil and gas and the commercial and industrial markets. The increase in the oil and gas market was as a result of an overall increase in drilling activity in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. The increase in the commercial and industrial market was due to an increase in construction activity. There was also an increase in the residential market due to colder weather conditions in our key markets. However, there was a decline in the automotive market, where declines have been occurring for several years as propane is not the preferred fuel choice. Overall retail propane revenues increased 27% in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010, primarily as a result of increased sales volumes.

Wholesale propane distribution volumes increased by 23% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, due to the impact of additional volumes from a major customer with whom we entered into an exclusive supply agreement in the latter part of 2010. As a result, revenues increased by 19% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010.

NGL marketing volumes increased 143% in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010, primarily as a result of the impact of the Taylor acquisition and also due to an increase in butane volumes sold to external customers and product used by our marketing segment.  Offset against this was a decrease in condensate volumes due to a decrease in demand from our marketing segment. NGL marketing revenues increased 148% due mainly to the impact of increased volumes.

Cost of sales per gallon in retail propane and wholesale distribution propane remained relatively stable in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. Retail propane margin per gallon remained relatively stable, decreasing by 1%. Wholesale propane distribution margin per gallon was 29% lower in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. This decrease was largely due an unfavorable impact of a weaker U.S. dollar relative to the Canadian dollar.

Cost of sales for NGL marketing increased 147% in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010, largely due to the impact of the Taylor acquisition.

Operating expenses and other.  Overall operating expenses and other costs increased by $1.6 million, or 15%, in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, primarily due an increase in payroll related costs and also the additional costs from the Taylor acquisition.

Segment profit.  The propane and NGL marketing and distribution segment profit increased in the three months ended March 31, 2011 by $4.4 million or 33% as compared to the three months ended March 31, 2010, primarily as a result of increased volumes and margins in retail propane and higher margins in NGL marketing.

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Processing and wellsite fluids

The following tables set forth operating results from our processing and wellsite fluids segment for the periods indicated:

	Three months ended March 31,
Volumes (barrels in thousands)	2011	2010
Roofing flux	396	395
Road asphalt	—	108
Frac fluid	163	195
Tops	406	353
Distillate	224	187
Other	21	8
Total sales volumes	1,210	1,246

	Three months ended March 31,
	2011		2010
	(in thousands)
Revenues
Road asphalt and roofing flux	$	33,087	$	40,405
Frac fluid	19,863		23,551
Tops	35,571		27,861
Distillate	28,606		27,665
Other	2,232		1,039
Total revenues	119,359		120,521
Cost of sales	104,462		107,787
Operating expenses and other	3,769		3,591
Segment profit	$	11,128	$	9,143

Three months ended March 31, 2011 and 2010.

Volumes, revenues and cost of sales.

Sales volumes for roofing flux remained stable in the three months ended March 31, 2011 compared to the three months ended March 31, 2010.  In the three months ended March 31, 2010, road asphalt sales volume related to customers purchasing in advance of the paving season to secure volumes and to take advantage of winter fill pricing. In the three months ended March 31, 2011, this did not occur and consequently there were no sales of road asphalt in the current year period. Road asphalt and roofing flux revenue decreased by 18% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010 due to the decrease in volumes.

Frac fluid revenues were 16% lower in the three months ended March 31, 2011 compared to the three months ended March 31, 2010, which was due to a decrease in volumes. Frac fluid volumes decreased 16% in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. Despite strong overall demand for frac fluids, the decrease was primarily due to an increase in market demand for water based frac fluids as opposed to oil based frac fluids.

Tops volumes were 15% higher in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The increase in volume is a result of a decrease in sales volumes of our frac fluid. When frac fluid volumes decline, we can sell the light end volume as tops. As a result, tops revenues were 28% higher over the same period, reflecting the increase in volumes and also the higher price of crude oil, particularly in March 2011, which is the basis for pricing tops.

Sales volumes for distillate were 20% higher in the three months ended March 31, 2011 compared to the three months ended March 31, 2010 due to an increase in drilling activity. Distillate revenues were 3% higher in the period as a result of higher volumes, which was offset by lower pricing as a result of increased competition.

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The overall cost per barrel for the basket of products sold by the processing and wellsite segment remained relatively stable. Despite an increase in crude prices, this was offset by wider price differentials, which had a positive impact on product margins.

Overall margins increased by $2.2 million, or 17%, in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The primary reason for the increase in overall margins was largely due to wider differentials for crude oil, which positively impacted our overall margins.

Operating expenses and other.  Operating expenses increased by $0.2 million or 5% in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010, primarily due to an increase in payroll and related costs.

Segment profit.  The processing and wellsite fluids segment profit increased in the three months ended March 31, 2011 by $2.0 million or 22% as compared to the three months ended March 31, 2010 primarily as a result of increased margins for tops. The selling price for tops increased, particularly in March, but crude oil input prices did not increase correspondingly due to wider price differentials for crude oil resulting in increased margins.

Marketing

The following tables set forth our operating results from our marketing segment:

	Three months ended March 31,
Volumes (barrels in thousands)	2011	2010
Sales Volumes
Crude and diluent	12,940	11,624
Natural gas (GJ)	5,510	10,462

	Three months ended March 31,
	2011		2010
	(in thousands)
Revenues
Crude and diluent	$	790,391	$	699,497
Natural gas	25,389		57,307
Edmonton North Terminal	—		113,920
Total revenues	815,780		870,724
Cost of sales	807,773		864,504
Operating expenses and other	3,181		3,586
Segment profit	$	4,826	$	2,634

Three months ended March 31, 2011 and 2010.

Volumes, revenues and cost of sales.

The monthly average NYMEX benchmark price of crude oil ranged from approximately U.S.$89.58 to U.S.$102.98 during the three months ended March 31, 2011 and from approximately U.S.$76.45 to U.S.$81.29 during the three months ended March 31, 2010.

Sales volumes for crude and diluent increased by 11% in the three months ended March 31, 2011, due to an increased focus on bringing volumes to our integrated assets by our marketing segment. As a result, revenue for crude and diluent increased by 13% due to the increase in volume and also the increase in commodity prices, particularly in March 2011.

Natural gas sales volumes decreased 47% in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010, primarily due to the expiration and non-renewal of gas contracts since March 31, 2009. As a result, natural gas revenues were 56% lower in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010.

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The decrease in revenue at our Edmonton North Terminal was as a result of the sale of the terminal on January 7, 2011.  Inventory at the terminal that was not sold as part of the transaction was sold subsequently and is included in our crude and diluent revenue.

Cost of sales in the three months ended March 31, 2011 was 7% lower compared to the three months ended March 31, 2010. This was mainly attributable to the decreases in revenue from natural gas and the Edmonton North Terminal.

Operating expenses and other.  Operating expenses decreased by $0.4 million in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. The decrease in costs was mainly as a result of the sale of the Edmonton North Terminal.

Segment profit.  Overall segment profit increased by approximately $2.2 million in the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. In the three months ended March 31, 2011 margins were positively impacted by the widening of the pricing differentials between crude oil types, which is generally beneficial for segment profitability. In the three months ended March 31, 2010, margins were negatively impacted by narrow price differentials between crude oil types.

General and administrative, excluding depreciation and amortiztion

General and administrative expense (“G&A”) is comprised of costs incurred for executive services, accounting, finance, legal, human resources and communications that are incurred at a corporate level and are not related to a specific segment of operations.

G&A expense was $6.0 million and $6.2 million in the three months ended March 31, 2011 and 2010, respectively. The decrease in G&A expenses was largely related to a decrease in payroll and related costs in the three months ended March 31, 2011 offset by an increase in office rent expense.

Depreciation and amortization

Depreciation and amortization expense was $23.8 million and $18.7 million in the three months ended March 31, 2011 and 2010, respectively. The increase relates primarily to the additional depreciation and amortization related to our acquisitions, primarily Taylor and BRT.

Stock based compensation

Stock based compensation expense was $0.6 million in the three months ended March 31, 2011 compared to $1.2 million in the three months ended March 31, 2010. The decrease in expense was largely due to the graded recognition of stock compensation expense, whereby each vesting installment is accounted for as a separate arrangement and expense is recognized over each installment’s vesting period. The decrease was also due to a reversal of expense due to the forfeiture of options in the three months ended March 31, 2011.

Foreign exchange loss (gain) not affecting segment profit

In the three months ended March 31, 2011, we recorded a foreign exchange gain of $16.4 million compared to $21.1 million in the three months ended March 31, 2010. The gain recorded in the three months ended March 31, 2011 and 2010 was primarily as a result of a favorable movement in exchange rates relating to our U.S. dollar denominated long-term debt.

Gain on sale of Edmonton North Terminal

On January 7, 2011, we completed the disposition of our Edmonton North Terminal to Pembina Midstream Limited Partnership for consideration of approximately $54.3 million, realizing a gain on the sale of $20.4 million.

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Interest expense, net

Net interest expense was $24.6 million in the three months ended March 31, 2011 compared to $23.8 million in the three months ended March 31, 2010. The increase is primarily due to a full quarter impact in the current year period of the issuance of our Senior Notes on January 19, 2010 offset by a stronger Canadian dollar compared to the U.S. dollar in the three months ended March 31, 2011 compared to the three months ended March 31, 2010.

Income tax expense

Income tax expense during the three months ended March 31, 2011 was $8.1 million compared to $3.2 million in the three months ended March 31, 2010. The effective tax rate was 16.8% during the three months ended March 31, 2011, compared to 22.4% during the three months ended March 31, 2010. The main reason for the increase in the income tax expense was due to an increase in income before tax in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. The effective tax rate decreased due mainly to the impact of the non-taxable portion of the Edmonton North Terminal gain in the current year period.

SUMMARY OF QUARTERLY RESULTS

The following table sets forth a summary of our quarterly results for each of the last eight quarters. The quarterly results after January 1, 2010 have been prepared in accordance with IFRS. The quarterly results prior to January 1, 2010 have been prepared in accordance with Canadian GAAP.

	IFRS											Canadian GAAP
	2011		2010									2009
	Three months ended
	March 31, 2011		December 31, 2010		September 30, 2010		June 30, 2010			March 31, 2010		December 31, 2009			September 30, 2009		June 30, 2009
	(in thousands)
Revenues	$	1,148,017	$	992,048	$	885,010	$	848,865		$	964,529	$	988,702		$	875,164	$	820,438
Net income (loss)	40,131		31,396		10,737		(50,172		)	10,981		(97,181		)	26,714		12,856
EBITDA(1)	96,744		84,497		59,991		(21,194		)	56,859		(69,423		)	72,065		49,060

(1)EBITDA consists of net income (loss) before interest expense, income taxes, depreciation, and amortization. You are encouraged to evaluate each adjustment and the reasons we consider it appropriate for supplemental analysis.

We present EBITDA because we consider it to be an important supplemental measure of our performance and believe this measure is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industries with similar capital structures. We believe issuers of “high yield” securities also present EBITDA because investors, analysts and rating agencies consider it useful in measuring the ability of those issuers to meet debt service obligations. We believe that EBITDA is an appropriate supplemental measure of debt service capacity because cash expenditures for interest are, by definition, available to pay interest, and income tax expense is inversely correlated to interest expense because income tax expense goes down as deductible interest expense goes up and depreciation and amortization are non-cash charges.

EBITDA has limitations as an analytical tool, and you should not consider this item in isolation, or as a substitute for an analysis of our results as reported under IFRS or Canadian GAAP. Some of these limitations are:

·EBITDA:

·excludes certain income tax payments that may represent a reduction in cash available to us;

·does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

·does not reflect the impact of the movement in exchange rates on our long-term debt;

·does not reflect changes in, or cash requirements for, our working capital needs; and

·does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments on our debt, including the Notes;

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·Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and

·Other companies in our industry may calculate EBITDA differently than we do, limiting its usefulness as a comparative measure.

Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to us to invest in the growth of our business. We compensate for these limitations by relying primarily on our IFRS results for the periods subsequent to January 1, 2010 and Canadian GAAP results for the period prior to January 1, 2010 and using EBITDA only supplementally. The following table reconciles net income to EBITDA:

	IFRS												Canadian GAAP
	2011		2010										2009
	Three months ended
	March 31, 2011		December 31, 2010		September 30, 2010			June 30, 2010			March 31, 2010		December 31, 2009			September 30, 2009		June 30, 2009
	(in thousands)
Net income (loss)	$	40,131	$	31,396	$	10,737		$	(50,172	)	$	10,981	$	(97,181	)	$	26,714	$	12,856
Depreciation and amortization	23,806		24,882		24,259			22,074			18,675		20,360			21,505		19,778
Interest expense	24,705		25,555		25,241			24,904			24,036		19,383			19,388		20,758
Income tax expense (recovery)	8,102		2,664		(246		)	(18,000		)	3,167		(11,985		)	4,458		(4,332		)
EBITDA	$	96,744	$	84,497	$	59,991		$	(21,194	)	$	56,859	$	(69,423	)	$	72,065	$	49,060

In addition, we present Pro Forma Adjusted EBITDA because it is used in calculating our covenant compliance under the indenture governing the First Lien Notes. EBITDA and Pro Forma Adjusted EBITDA as presented herein are not recognized measures under IFRS or Canadian GAAP and should not be considered as an alternative to operating income or net income as measures of operating results or an alternative to cash flows as measures of liquidity. Pro Forma Adjusted EBITDA differs from the term EBITDA as it is commonly used. Pro Forma Adjusted EBITDA is defined as consolidated net income (loss) before interest expense, income taxes, depreciation, amortization, other non-cash expenses and charges deducted in determining consolidated net income (loss), including movement in the unrealized gains and losses on our financial instruments, stock based compensation expense, impairment of goodwill and intangible assets, and non-cash inventory writedowns. It also takes into account, among other things, the impact of foreign exchange movements in our U.S. dollar denominated long-term debt, management fees, the pro forma effect of acquisitions that took place subsequent to March 31, 2010 and other adjustments that are considered non-recurring in nature.

These covenants limit our ability to take certain actions such as incurring additional debt or making certain payments or certain investments if the ratio of our Pro Forma Adjusted EBITDA to Pro Forma Consolidated Interest Expense is less than two to one on a trailing four-quarter basis. For the twelve months ended March 31, 2011, our ratio of Pro Forma Adjusted EBITDA to Pro Forma Consolidated Interest Expense was 2.0:1. We believe that disclosing the Pro Forma Adjusted EBITDA and the ratio of Pro Forma Adjusted EBITDA to Pro Forma Consolidated Interest Expense that is used to calculate our debt covenants provides supplemental information to investors about our ability to comply with the covenants under the indenture governing the Notes and, therefore, our ability to obtain additional debt in the future.

Our calculation of Pro Forma Adjusted EBITDA may not be comparable to such calculations used in debt covenants by other companies. In calculating Pro Forma Adjusted EBITDA, we make certain adjustments that are based on assumptions and estimates that may prove to have been inaccurate. In addition, in evaluating Pro Forma Adjusted EBITDA, you should be aware that in the future we may incur expenses similar to those eliminated in this presentation.

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The following table reconciles EBITDA to Pro Forma Adjusted EBITDA for each of the last four quarters and for the twelve months ended March 31, 2011:

	IFRS
	Three months ended												Twelve months ended
	March 31, 2011			December 31, 2010			September 30, 2010			June 30, 2010			March 31, 2011
	(in thousands)
EBITDA	$	96,744		$	84,497		$	59,991		$	(21,194	)	$	220,038
Unrealized foreign exchange loss (gain) on long-term debt(a)	(17,328		)	(26,752		)	(23,408		)	34,200			(33,288		)
Net unrealized loss (gain) from financial instruments(b)	(3,034		)	(1,787		)	1,639			(1,986		)	(5,168		)
Employee stock option plan(c)	621			475			1,744			1,260			4,100
Recent acquisitions(d)	—			—			414			2,627			3,041
EBITDA adjustments relating to associates (e)	576			449			410			634			2,069
Management fee(f)	306			255			260			256			1,077
Gain on sale of assets (g)	(20,370		)	—			—			—			(20,370		)
Acquisition related transaction costs (h)	—			—			—			2,359			2,359
Non-recurring charges(i)	—			—			2,543			—			2,543
Pro Forma Adjusted EBITDA	$	57,515		$	57,137		$	43,593		$	18,156		$	176,401

(a)Non-cash adjustment representing the unrealized foreign exchange loss (gain) on long-term debt, as a result of the movement in exchange rates in the periods.

(b)Reflects the exclusion of the change in net unrealized gains or losses attributable to movement in the mark-to-market valuation of financial instruments used in commodity price risk management activities. We use oil and gas price futures, options and swaps to manage the exposure to oil and gas price movements and foreign currency forward contracts and options to manage foreign exchange risks, although we do not formally designate these financial instruments as hedges for IFRS accounting purposes. Accordingly, the unrealized gains or losses on these financial instruments are recorded directly to the income statement. Management believes that this adjustment better correlates the effect of risk management activities to the underlying operating activities to which they relate.

(c)Represents the stock based compensation relating to the Company adopted equity incentive plan.

(d)Reflects the pro forma effect of our acquisitions of Taylor and BRT on our Pro Forma Adjusted EBITDA as if the acquisitions took place on April 1, 2010.

(e)Represents the adjustment to add back interest expense, income taxes, depreciation and amortization that is included in the Company’s share of the results from associates.

(f)Reflects an adjustment for the management fee payable to Riverstone.

(g)Represents the gain of $20.4 million on the sale of the Edmonton North Terminal on January 7, 2011.

(h)Reflects an adjustment for transaction fees incurred in connection with acquisitions that are expensed as they are incurred.

(i)Represents a $2.5 million charge in the three months ended September 30, 2011 as a result of the Company subleasing excess office space at less than the amount payable on the head lease.

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LIQUIDITY AND CAPITAL RESOURCES

Our primary liquidity and capital resource needs are to service our debt, including interest payments, to finance working capital needs, to fund ongoing capital expenditures and to fund growth opportunities and acquisitions. We rely on our cash flow from operations, debt financings and borrowings under our Credit Facility for liquidity.

We believe that we have sufficient liquidity at March 31, 2011 and cash flow from operations to fund most of our growth and capital expenditures. However, we may have to access additional capital from Riverstone or the capital markets should we require additional funds, but we can give no assurance that funds will be available on acceptable terms.  On April 27, 2011, our affiliate Gibson Energy Inc. filed a preliminary prospectus with the securities regulatory authority in each of the provinces and territories of Canada, whereby it intends to complete an initial public offering of its common shares. Concurrently, we intend to enter into a new senior secured first lien term loan facility in an aggregate principal amount of up to U.S.$700.0 million and a revolving credit facility of up to U.S.$250.0 million. We intend to use the proceeds from the Offering and the Refinancing to refinance our outstanding Notes through either an offer to purchase for cash any and all of the outstanding Notes or through satisfaction and discharge, defeasance or a manner otherwise permitted under the respective indentures governing the Notes, to repay any amounts outstanding under the Credit Facility, to fund growth and for general corporate purposes.

Our operating cash flow has historically been affected by the overall profitability of sales within our segments, our ability to invoice and collect from customers in a timely manner and our ability to efficiently implement our acquisition strategy and manage costs. Our cash, cash equivalents and cash flow from operations have historically been sufficient to meet our working capital, capital expenditure and debt servicing requirements.

The following table summarizes our sources and uses of funds for the three months ended March 31, 2011 and 2010:

	Three months ended March 31,
	2011			2010
	(in thousands)
Statement of Cash Flows
Cash flows provided by (used in):
Operating activities	$	63,571		$	23,381
Investing activities	36,106			(30,381		)
Financing activities	(54,326		)	167,588

Cash provided by operating activities

The primary drivers of cash flow from operating activities are the collection of amounts related to sales of crude oil, propane, asphalt and other products and fees for services provided associated with our truck transportation and terminal and pipeline services. Offsetting these collections are payments for purchases of crude oil and other products and other expenses. These other expenses primarily consist of owner-operator and lease operator payments for the provision of contract trucking services, field operating expenses and administrative G&A expenses. Historically, the marketing and processing and wellsite fluids segments have been the most variable with respect to generating cash flows due to the impact of crude oil price levels and the volatility that price changes and crude oil grade basis changes have on the cash flows and working capital requirements of these segments.

Cash provided by operations in the three months ended March 31, 2011 was $63.6 million compared to $23.4 million in the three months ended March 31, 2010. The increase was primarily attributable to an increase in overall profitability in the three months ended March 31, 2011 compared to the three months ended March 31, 2010.  In addition, inventory decreased by $39.3 million in the three months ended March 31, 2011 compared to an increase in inventory of $9.2 million in the three months ended March 31, 2010.  Offset against this was a net increase in accounts receivable and payable of $39.4 million in the three months ended March 31, 2011 compared to a decrease of $14.7 million in the three months ended March 31, 2010.

Cash provided by (used in) investing activities

Cash used in investing activities consists primarily of expenditures for capital projects and business acquisitions.

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Cash provided by investing activities in the three months ended March 31, 2011 was $36.1 million compared to cash used in investing activities of $30.4 million in the three months ended March 31, 2010. The increase was largely related to the proceeds from the sale of assets of $54.5 million, which was largely related to the sale of our Edmonton North Terminal. In addition, it was also as a result of a decrease in business acquisitions in the three months ended March 31, 2011 compared to the three months ended March 31, 2010. We did not complete any business acquisitions in the three months ended March 31, 2011 compared to cash outflow for the acquisitions of Johnstone and Aarcam of $24.7 million in the three months ended March 31, 2010. Offset against this was an increase in capital expenditures in the three months ended March 31, 2011 of $23.4 million compared to $8.5 million in the three months ended March 31, 2010, respectively.

Cash (used in) provided by financing activities

Cash used by financing activities in the three months ended March 31, 2011 was $54.3 million, compared to cash provided by financing activities of $167.6 million in the three months ended March 31, 2010. The cash used by financing activities in the three months ended March 31, 2011 was largely related to the net repayment of $43.5 million of our Credit Facility. In addition, in the three months ended March 31, 2011, we paid interest of $10.9 million, which largely related to the scheduled interest payment on our Senior Notes. The cash provided by financing in the three months ended March 31, 2010 was a result of the issuance of the Senior Notes in an aggregate principal amount of U.S.$200.0 million. Additionally, in connection with the issuance of the Senior Notes, we paid debt issuance costs of $6.5 million and a debt discount of $5.7 million. Offset against this was the repayment of $25.0 million of our Credit Facility.

As of March 31, 2011, we had total outstanding long-term debt, excluding debt issuance costs, of U.S.$760.0 million, comprised of the First Lien Notes in an aggregate principal amount of U.S.$560.0 million and the Senior Notes in an aggregate principal amount of U.S.$200.0 million. The First Lien Notes have a term of five years expiring on May 27, 2014, and accrue interest at 11.75% per annum. The Senior Notes have a term of eight years expiring on January 15, 2018, and accrue interest at 10.0% per annum. The First Lien Notes and the Senior Notes are guaranteed by all of our existing material wholly owned subsidiaries. Additionally, we have a Credit Facility of up to U.S.$200.0 million, the proceeds of which are available to provide financing for working capital and other general corporate purposes. At March 31, 2011, we did not have any amount drawn against this facility and we had issued letters of credit totalling $82.6 million. We are currently utilizing U.S.$10.0 million of the facility for our U.S. operations, with the remainder of the U.S.$200.0 million available for use by our Canadian operations, all subject to certain borrowing base requirements. At March 31, 2010, we had restricted cash of $0.5 million.

The terms of our Credit Facility require us to maintain a “Fixed Charge Coverage Ratio” of not less than 1.1:1, following any period of 3 consecutive days in which availability is less than an amount equal to 15% of the commitments by the lenders under the Credit Facility. As of March 31, 2011, we had no amounts drawn and issued letters of credit of $82.6 million against the facility, and therefore the compliance with the financial ratio was not applicable. If we fail to comply with the financial covenants, the lenders may declare an event of default under the Credit Facility. An event of default resulting from a breach of a financial covenant may result, at the option of lenders holding a majority of the loans, in an acceleration of repayment of the principal and interest outstanding and a termination of the Credit Facility, and could result in an acceleration of amounts due and payable under the Notes. In addition, the facility contains a provision that requires prior written consent for acquisitions exceeding annual consideration of U.S.$80.0 million, exclusive of acquisitions funded by permitted equity or debt raised to finance such transactions.

The Notes and the Credit Facility also contain non-financial covenants that restrict some of our activities, including our ability to dispose of assets, incur additional debt, pay dividends, create liens, make investments and engage in specified transactions with affiliates. In connection with the First Lien Notes, following the sale of our Edmonton North Terminal, we are required to acquire collateral assets of approximately $55.0 million within 545 days after the sale. The Notes and the Credit Facility also contain customary events of default, including defaults based on events of bankruptcy and insolvency, non-payment of principal, interest or fees when due, subject to specified grace periods, breach of specified covenants, change in control and material inaccuracy of representations and warranties. As of March 31, 2011, we were in compliance with all of our covenants under our Notes and Credit Facility.

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Liquidity sources, requirements and contractual cash requirement and commitments

We believe that our cash on hand, together with cash from operations and borrowings under our Credit Facility, will be adequate to meet our working capital needs, planned capital expenditures, debt service and other cash requirements for at least the next twelve months. At March 31, 2011, we had unrestricted cash of $51.5 million and $111.8 million available under the Credit Facility.

Our ability to make scheduled payments of principal, to pay interest on and to refinance our indebtedness, and to fund our other liquidity requirements will depend on our ability to generate cash in the future. Capital expenditures amounted to $23.4 million in the three months ended March 31, 2011. We have identified and approved additional capital projects (excluding acquisitions) of $203.9 million that we expect to undertake over the next 12 to 18 months. While we anticipate that these capital expenditures and acquisitions will occur, they are subject to general economic, financial, competitive, legislative, regulatory and other factors, some of which are beyond our control.

In addition to anticipated capital expenditures and acquisitions, we may engage in additional strategic acquisitions and capital expenditures as opportunities arise that benefit our existing operations by expanding our reach in existing markets or by providing platforms with which to enter new markets. Any such acquisition or capital expenditure could be material and could have a material effect on our liquidity, cash flows and capital commitments and resources. Any future acquisitions, capital expenditures or other similar transactions will likely require additional capital and there can be no assurance that any such capital will be available to us on acceptable terms, if at all.

The indentures governing the Notes limit our ability to incur additional indebtedness or to make certain acquisitions unless we meet or exceed a consolidated interest coverage ratio, which is based in part on our Pro Forma Adjusted EBITDA during the most recently ended four-quarter period. Because our Pro Forma Adjusted EBITDA may fluctuate materially from period to period, we cannot assure you that we will always meet the interest coverage ratio.  At March 31, 2011, we did meet this ratio.

On April 27, 2011, our affiliate, Gibson Energy Inc., filed a preliminary prospectus with the securities regulatory authority in each of the provinces and territories of Canada, whereby it intends to complete an initial public offering of its common shares. Concurrent with the Offering, we intend to enter into a series of transactions intended to refinance our existing indebtedness whereby we expect to enter into a new senior secured first lien term loan facility in an aggregate principal amount of up to U.S.$700.0 million, with a term of seven years, and a revolving credit facility of up to U.S.$250.0 million, with a term of five years.  We intend to use the proceeds from the Offering and the Refinancing to refinance our outstanding Notes through either an offer to purchase for cash any and all of the outstanding Notes or through satisfaction and discharge, defeasance or a manner otherwise permitted under the respective indentures governing the Notes, to repay any amounts outstanding under our Credit Facility and for general corporate purposes.

Contingencies

Two of our companies are currently undergoing various income tax related audits. While the final outcome of such audits cannot be predicted with certainty, we do not believe that the resolution of these audits will have a material impact on our consolidated financial position or results of operations. As part of the acquisition of us by Riverstone from Hunting PLC (“Hunting”) on December 12, 2008, Hunting has indemnified us for any increased income taxes as a result of these audits relating to periods prior to the acquisition date.

We are subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to the contractual agreements and management decisions, result in the recognition of estimated asset retirement obligations and environmental remediation. Estimates of asset retirement obligation and environmental remediation costs can change significantly based on such factors as operating experience and changes in legislation and regulations.

We are involved in various legal actions, which have occurred in the ordinary course of business. We are of the opinion that losses, if any, arising from such legal actions would not have a material impact on our consolidated financial position or results of operations.

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Contractual obligations

The following table presents, at March 31, 2011, our obligations and commitments to make future payments under contracts and contingent commitments:

	Payments due by period
(in thousands)	Total		Remainder of the year		1-3 years		3-5 years		More than 5 years
Long-term debt(1)	$	738,568	$	—	$	544,208	$	—	$	194,360
Interest payments on long-term debt(1)	359,330		73,664		166,764		70,312		48,590
Operating lease obligations	112,972		13,755		30,277		22,427		46,513
Total contractual obligations	$	1,210,870	$	87,419	$	741,249	$	92,739	$	289,463

(1)The exchange rate used to translate the U.S. dollar obligations on our long-term debt and interest payments is the rate as of March 31, 2011 of U.S.$1.0290 to $1.00.

OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditure or capital expenses that are material to investors.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are involved in various commodity related marketing activities that are intended to enhance our operations and increase profitability. These activities often create exposure to price risk between the time contracted volumes are purchased and sold and to foreign exchange risk when contracts are in different currencies (Canadian dollar versus U.S. dollar). We are also exposed to various market risks, including volatility in (i) crude oil, refined products, natural gas and propane and NGL prices, (ii) interest rates and (iii) currency exchange rates. We utilize various derivative instruments to manage commodity price and currency rate exposure and, in certain circumstances, to realize incremental margin during volatile market conditions. Our commodity trading and risk management policies and procedures are designed to establish and manage to an approved level of Value at Risk. We have a Risk Management Committee that has direct responsibility and authority for our risk policies and our trading controls and procedures and certain aspects of corporate risk management. Our approved strategies are intended to mitigate risks that are inherent in our core businesses of gathering and marketing and storage. To hedge the risks discussed above we engage in risk management activities that we categorize by the risks we are hedging and by the physical product that is creating the risk. The following discussion addresses each category of risk.

Commodity Price Risk.  We hedge our exposure to price fluctuations with respect to crude oil, refined products, natural gas and NGL’s, and expected purchases and sales of these commodities.  The derivative instruments utilized consist primarily of futures, swaps and option contracts traded on the NYMEX, ICE and over-the-counter transactions entered into with financial institutions and other energy companies. Our policy is to financially buy and sell only commodity products for which we physically transact, and to structure our hedging activities so that price fluctuations for those products do not materially affect the segment profit we receive.

Although we seek to maintain a position that is substantially balanced within our various commodity purchase and sales activities we may experience net unbalanced positions as a result of production, transportation and delivery variances as well as logistical issues associated with inclement weather conditions.

Although the intent of our risk management strategies is to hedge our margin, we have not designated nor attempted to qualify for hedge accounting. Thus, changes in the fair values of all of our derivatives are recognized in earnings, and result in greater potential for earnings volatility.

The fair value of futures contracts is based on quoted market prices obtained from the NYMEX. The fair value of swaps and option contracts is estimated based on quoted prices from various sources such as independent reporting services, industry

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publications and brokers. These quotes are compared to the contract price of the swap, which approximates the gain or loss that would have been realized if the contracts had been closed out at the period end. For positions where independent quotations are not available, an estimate is provided, or the prevailing market price at which the positions could be liquidated is used. No such positions existed as at March 31, 2011 and December 31, 2010. All derivative positions offset physical exposures to the cash market. Price-risk sensitivities were calculated by assuming a 15% volatility in crude oil related prices, regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an increase or decrease in crude oil prices, the fair value of our derivative portfolio would typically increase or decrease, offsetting changes in our physical positions. A 15% favorable change would increase our net income by $2.1 million and $4.8 million in the three months ended March 31, 2011 and the three months ended March 31, 2010, respectively. A 15% unfavorable change would decrease our net income by $2.7 million and $4.8 million in the three months ended March 31, 2011 and the three months ended March 31, 2010, respectively. However, these changes may be offset by the use of one or more risk management strategies.

Electricty Price Risk.  We have hedged our exposure to electricity price fluctuations by entering into a financial swap contract to fix the level of anticipated electricity costs that are price sensitive to the Alberta Electric System Operator (AESO) Pool Price.  If the actual AESO Pool Price is greater than the bought fixed price per megawatt hour, we receive the difference between that price and the bought fixed price per megawatt hour.  If the actual AESO Pool Price is less than the bought fixed price per megawatt hour, we pay the difference between that price and the bought fixed price per megawatt hour.  A 10% favorable change would increase our net income by $0.2 million and $0.3 million as of March 31, 2011 and 2010, respectively.  A 10% unfavorable change would decrease our net income by $0.2 million and $0.3 million as of March 31, 2011 and 2010, respectively.

Interest rate risks.  The amounts outstanding under the First Lien Notes and Senior Notes accrue interest at a fixed rate of 11.75% and 10.0% per annum, respectively. Therefore, any change in interest rates would not have an impact on our net income.

Under our Credit Facility, we are subject to interest rate risk, as borrowings bear interest at a rate equal to, at the Company’s option, either LIBOR, the lenders prime rate, the Bankers’ Acceptance rate or the Above Bank Rate, plus an applicable margin based on a pricing grid. For the three months ended March 31, 2011, the impact on net income for a 100 basis point change in interest rates on the outstanding amount under our Credit Facility was not material.

Currency exchange risks.  Our assets and liabilities in foreign currencies are translated at the period-end rate. Exchange differences arising from this translation are recorded in our statement of operations. In addition, currency exposures can arise from revenues and purchase transactions denominated in foreign currencies. Generally, transactional currency exposures are naturally hedged (i.e., revenues and expenses are approximately matched), but where appropriate, are covered using forward exchange contracts. All of the foreign currency forward exchange contracts entered into by us, although effective hedges from an economic perspective, have not been designated as hedges for accounting purposes, and therefore any gains and losses on such forward exchange contracts impact our earnings. Additionally, currency exposure occurs on the principal of our long-term debt and the related interest payments, as they are both denominated in U.S. dollars.  To date we have not entered into any hedges on the principal of our long-term debt but we have entered into foreign exchange option contracts and U.S. dollar forward contracts on our U.S. dollar interest payments.

A 5% unfavorable change in the value of the Canadian dollar relative to the U.S. dollar would affect the fair value of our outstanding forward currency contracts and would decrease our net income by $1.9 million and $1.1 million in the three months ended March 31, 2011 and in the three months ended March 31, 2010, respectively. A corresponding favorable change would increase our net income by $1.9 million and $1.1 million in the three months ended March 31, 2011 and in the three months ended March 31, 2010, respectively. We expect to continue to enter into financial derivatives, primarily forward contracts, to reduce foreign exchange volatility. We are exposed to credit loss in the event of non-performance by the other party to the derivative financial instruments. We mitigate this risk by entering into agreements directly with a number of major financial institutions that meet our credit standards and that we expect to fully satisfy their contractual obligations. We view derivative financial instruments purely as a risk management tool and, therefore, do not use them for speculative trading purposes.

As at March 31, 2011, we had outstanding U.S. dollar denominated debt of U.S.$760.0 million. A 5% unfavorable change in the value of the Canadian dollar relative to the U.S. dollar would impact the carrying value of our long-term debt and would decrease our net income by $31.8 million and $33.2 million in the three months ended March 31, 2011 and in the three

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months ended March 31, 2010, respectively. A corresponding favorable change would increase our net income by $31.8 million and $33.2 million in the three months ended March 31, 2011 and in the three months ended March 31, 2010, respectively. Our long-term debt accrues interest at fixed interest rates or U.S.$85.8 million per annum. A 5% unfavorable change in the value of the Canadian dollar relative to the U.S. dollar as of March 31, 2011 would increase our annual interest expense by $4.2 million. A 5% favorable change in the value of the Canadian dollar relative to the U.S. dollar as of March 31, 2011 would decrease our annual interest expense by $4.2 million.

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