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 Six Month Period Ended June 30, 2010

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 Sheets

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	June 30, 2010		December 31, 2009
Assets
Current assets
Cash and cash equivalents (note 5)	$	38,989	$	26,263
Accounts receivable	333,035		315,865
Income taxes receivable	34,821		11,050
Inventories (note 2)	124,068		113,688
Current portion of future income taxes (note 9)	—		1,509
Prepaid expenses	6,800		5,187
Total current assets	537,713		473,562
Future income taxes (note 9)	6,353		5,225
Long-term prepaid expenses and other assets	37,628		35,432
Property, plant and equipment	642,235		598,826
Intangible assets	173,937		126,955
Goodwill	502,861		433,894
Total assets	$	1,900,727	$	1,673,894

See accompanying notes

Gibson Energy Holding ULC

Condensed Consolidated Balance Sheets

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	June 30, 2010			December 31, 2009
Liabilities
Current liabilities
Liquidity facility (note 5)	$	28,731		$	25,000
Accounts payable and accrued charges	332,950			268,274
Income taxes payable	2,681			8,443
Current portion of future income taxes (note 9)	839			839
Total current liabilities	365,201			302,556
Asset retirement obligation (note 4)	9,275			8,287
Long-term debt (note 6)	764,837			553,942
Other long-term liabilities (note 7)	16,133			16,092
Future income taxes (note 9)	189,691			204,373
Shareholder’s Equity
Share capital
Authorized
Unlimited Class A and Class B common voting shares without nominal or par value
Issued
537,656 Class A common voting shares without nominal or par value	537,656			537,656
100,000 preferred non-voting shares without nominal or par value	119,816			113,034
Total share capital	657,472			650,690
Contributed surplus (note 11)	11,367			8,957
Accumulated other comprehensive income	4,175			—
Deficit	(117,424		)	(71,003		)
Total shareholder’s equity	555,590			588,644
Total liabilities and shareholder’s equity	$	1,900,727		$	1,673,894

See accompanying notes

Gibson Energy Holding ULC

Condensed Consolidated Statements of Income (Loss) and Retained Earnings (Deficit)

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Revenue
Products	$	755,903		$	749,166		$	1,637,631		$	1,445,406
Services	92,141			71,272			174,650			144,865
Total revenues	848,044			820,438			1,812,281			1,590,271
Cost of sales, excluding depreciation and amortization
Cost of products	772,493			743,572			1,633,509			1,397,369
Cost of services	54,726			50,234			113,989			103,192
Total cost of sales, excluding depreciation and amortization	827,219			793,806			1,747,498			1,500,561
	20,825			26,632			64,783			89,710
Operating expenses
Depreciation of property, plant and equipment	16,010			13,356			29,904			27,667
General and administrative	6,270			9,610			12,508			15,452
Amortization of intangible assets	7,144			6,422			12,982			12,779
Stock based compensation (note 11)	1,260			—			2,410			—
Loss on sale of assets	22			61			26			61
Other non-operating expenses (income)
Accretion expense	193			116			393			229
Foreign exchange loss (gain)	32,447			(50,735		)	12,178			(29,577		)
Debt extinguishment costs	—			18,517			—			18,517
Loss from investment in associates	54			108			558			286
Interest expense (income)
Long-term debt	24,340			20,598			47,791			41,808
Income	(62		)	(105		)	(278		)	(197		)
Liquidity facility and other	466			160			933			289
	88,144			18,108			119,405			87,314
Income (loss) before income taxes	(67,319		)	8,524			(54,622		)	2,396
Income tax recovery (note 9)
Current	1,200			(64		)	3,067			666
Future	(18,987		)	(4,268		)	(18,050		)	(5,788		)
	(17,787		)	(4,332		)	(14,983		)	(5,122		)
Net income (loss) for the period	(49,532		)	12,856			(39,639		)	7,518
Retained earnings (deficit) — beginning of period	(64,481		)	(3,983		)	(71,003		)	4,355
Dividends on preferred shares	(3,411		)	(3,000		)	(6,782		)	(6,000		)
Retained earnings (deficit) — end of period	$	(117,424	)	$	5,873		$	(117,424	)	$	5,873

See accompanying notes

Gibson Energy Holding ULC

Condensed Consolidated Statement of Comprehensive Income (Loss)

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	Three months ended June 30,					Six months ended June 30,
	2010			2009		2010			2009
Net income (loss)	$	(49,532	)	$	12,856	$	(39,639	)	$	7,518
Other comprehensive income , net of tax
Foreign currency translation adjustment	4,175			—		4,175			—
Comprehensive income (loss)	$	(45,357	)	$	12,856	$	(35,464	)	$	7,518

See accompanying notes

Gibson Energy Holding ULC

Condensed Consolidated Statement of Cash Flows

(Unaudited)

(tabular amounts in thousands of Canadian dollars)

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Cash provided by (used in)
Operating activities
Net income (loss)	$	(49,532	)	$	12,856		$	(39,639	)	$	7,518
Items not affecting cash
Depreciation and amortization	23,154			19,778			42,886			40,446
Stock based compensation	1,260			—			2,410			—
Future income taxes	(18,987		)	(4,268		)	(18,050		)	(5,788		)
Accretion expense	193			116			393			229
Accretion related to long-term debt	1,656			3,802			3,151			9,233
Loss on disposal of assets	22			61			26			61
Other long-term liabilities	(82		)	(127		)	(48		)	(493		)
Unrealized loss (gain) on financial instruments	(1,986		)	5,998			(1,290		)	14,010
Foreign exchange loss (gain) on long-term debt	34,200			(53,828		)	13,400			(33,087		)
Foreign exchange loss (gain) on cash and cash equivalents	(716		)	—			593			—
Debt extinguishment costs	—			18,517			—			18,517
Net change in non-cash working capital	(1,802		)	(20,523		)	4,245			(66,384		)
Net cash provided by (used in) operating activities	(12,620		)	(17,618		)	8,077			(15,738		)
Investing activities
Purchase of property, plant and equipment	(13,173		)	(6,788		)	(21,174		)	(13,250		)
Proceeds on disposal of assets	110			595			250			595
Equity investment in associates	(3,050		)	—			(3,050		)	—
Increase in long-term prepaid and other assets	420			(2,995		)	854			(3,833		)
Acquisitions, net of cash acquired (note 3)	(153,039		)	(6,900		)	(177,776		)	(6,900		)
Net change in non-cash working capital	2,030			(29,771		)	4,472			(31,512		)
Net cash used in investing activities	(166,702		)	(45,859		)	(196,424		)	(54,900		)
Financing activities
Proceeds from long-term debt, net of debt discount (note 6)	—			622,720			200,888			622,720
Payment of debt issue costs	—			(32,901		)	(6,544		)	(32,901		)
Repayments of bridge loans	—			(606,040		)	—			(606,040		)
Proceeds from liquidity facility	99,524			—			99,524			—
Repayment of liquidity facility	(70,793		)	—			(95,793		)	—
Net change in non-cash working capital	(269		)	—			—			—
Net cash provided by (used in) financing activities	28,462			(16,221		)	198,075			(16,221		)
Effect of exchange rate on cash and cash equivalents	4,307			—			2,998			—
Net increase (decrease) in cash and cash equivalents	(146,553		)	(79,698		)	12,726			(86,859		)
Cash and cash equivalents — beginning of period	185,542			105,791			26,263			112,952
Cash and cash equivalents — end of period	$	38,989		$	26,093		$	38,989		$	26,093

See accompanying notes

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

1Accounting policies

Basis of preparation

Gibson Energy Holding ULC (“Gibson” or the “Company”) was incorporated on September 23, 2008 by investment funds affiliated with Riverstone Holdings LLC (“Riverstone”), in order to acquire the outstanding common stock of Gibson Energy Holdings Inc. from Hunting PLC (“Hunting”). Effective on the close of business on December 12, 2008, Gibson acquired Gibson Energy Holdings Inc. for $1,256,390,000 (the “Acquisition”).

The Company is engaged in the transportation, storage, blending, processing, marketing and distribution of crude oil, condensate, NGLs such as propane and butane, refined products and natural gas.

These condensed consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). Canadian GAAP differs in certain respects from the accounting principles generally accepted in the United States of America (“U.S. GAAP”).  A description of the significant measurement and disclosure differences and their effects on net income and shareholder’s equity is set forth in Note 15.

The Company’s significant accounting policies are disclosed in Note 1 in the Company’s audited consolidated financial statements for the year ended December 31, 2009.  The Company’s accounting policies have not changed significantly as of June 30, 2010. These condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for the fair statement of the company’s financial position as of June 30, 2010, its results of operations for the three and six months ended June 30, 2010 and 2009, and its cash flows for the three and six months ended June 30, 2010 and 2009. The disclosures provided below are incremental to those included in the Company’s audited consolidated financial statements. The results of the interim periods are not necessarily indicative of the results to be expected for any future period or for the year ended December 31, 2010.

Amounts are stated in Canadian dollars unless otherwise noted. References to “$” and “dollars” are to Canadian dollars and references to “U.S.$” and “U.S. Dollars” are to United States dollars.

Recent accounting pronouncements

The Company has assessed new and revised accounting pronouncements that have been issued but are not yet adopted and determined that the following may have an impact on the Company:

a) Business combinations

The CICA issued Handbook Section 1582 Business Combinations, which replaces Section 1581. This new standard is effective for business combinations entered into on or after January 1, 2011 and affects the accounting and related expenses incurred at the date a business combination closes. The adoption of the revised standard is expected to impact the Company’s financial statements only to the extent that business combinations are entered into after the effective date.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

b) Consolidated financial statements

The CICA issued Handbook Section 1601 Consolidated Financial Statements that discusses consolidation accounting following a business combination that involves a purchase of an equity interest by one company in another. This new standard is effective for fiscal years beginning on or after January 1, 2011. The Company is in the process of evaluating the new standard and has not determined its impact on the Company’s financial statements.

2Inventories

	June 30, 2010		December 31, 2009
Crude oil	$	66,545	$	56,629
Diluent	7,040		6,257
Asphalt	18,808		23,381
Natural gas liquids	20,425		17,728
Natural gas	58		684
Wellsite fluids and distillate	8,952		7,244
Spare parts and other	2,240		1,765
	$	124,068	$	113,688

3Business 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.

On January 31, 2010, the Company purchased 100 percent of the common shares of Johnstone Tank Trucking Ltd. for cash, net of cash acquired, of $21,266,000.  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 our market presence in southern Saskatchewan and provide access to activity related to the Bakken oil fields.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:

Property, plant and equipment	$	7,892
Accounts receivable	4,395
Inventories	141
Prepaid expenses	352
Goodwill (1)	6,656
Intangible assets (2)	7,687
Accounts payable 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 customer relationships and a non-compete agreement.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

On February 1, 2010, the Company purchased 100 percent of the common shares of Aarcam Propane & Construction Heat Ltd. a propane retailer in Calgary, for cash, net of cash acquired, of $3,437,000.  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:

Property, plant and equipment	$	1,628
Accounts receivable	864
Inventories	55
Goodwill (1)	860
Intangible assets (2)	922
Accounts payable 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 customer relationships and a non-compete agreement.

On May 14, 2010, the Company purchased 100 percent of the outstanding equity of Taylor Companies LLC, a Delaware limited liability company, as well as certain assets of Taylor Propane Gas Inc. (collectively “Taylor”), for cash, net of cash acquired, of approximately $153,073,000.  Taylor is an independent for-hire crude oil transportation, logistics and crude oil and NGL marketing business with operations and facilities, including pipeline injection stations, in most crude oil processing states in the United States, thereby expanding our presence as a North American midstream Company.  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:

Property, plant and equipment	$	41,835
Accounts receivable	18,896
Inventories	4,505
Prepaid expenses	1,365
Goodwill	60,008
Intangible assets (1)	50,012
Accounts payable and accrued charges	(22,881		)
Other long-term liabilities	(667		)
Net assets acquired	$	153,073

(1)Consists of customer relationships and a non-compete agreement.

The initial accounting for assets and liabilities, including the fair value of property, plant and equipment, intangible assets and income taxes, has not been finalized, and therefore the allocation of the purchase price is subject to change.  The Company expects to finalize the purchase accounting in fiscal 2010.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

4Asset retirement obligation

As at June 30, 2010 and December 31, 2009, the carrying amount of the obligation associated with the retirement of terminal sites, asphalt refinery, fractionation plant and injection stations was $9,275,000 and $8,287,000 respectively.  The Company recorded accretion expense of $193,000 and $393,000 for the three and six months ended June 30, 2010, respectively, and $116,000 and $229,000 for the three and six months ended June 30, 2009, respectively.

The Company currently estimates the total undiscounted amount of estimated cash flows to settle the future liability for asset retirement obligation to be approximately $74,139,000 at June 30, 2010. These obligations are discounted using a weighted average credit adjusted risk-free rate of 8.5%, an annual inflation rate of 2% and are expected to be settled between 4 to 41 years into the future. In particular, the terminals, refinery and fractionation plant are expected to be settled within 39 years.

5Credit facilities

On December 12, 2008, the Company established with its lenders a revolving credit facility of up to U.S.$65,000,000 (the “Liquidity Facility”), the proceeds of which are available to provide financing for working capital and other general corporate purposes of the Company and its subsidiaries. On October 2, 2009, the Company increased its maximum amount to U.S.$95,000,000. On January 19, 2010, the Company increased its maximum amount to U.S.$150,000,000.

The Liquidity Facility has a term of four years expiring on December 12, 2012. Borrowings under the Liquidity 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 drawn $28,731,000 and $25,000,000 against the Liquidity Facility, as at June 30, 2010 and December 31, 2009, respectively. In addition, the Company has issued Letters of Credit totalling $21,089,000 and $9,800,000 as at June 30, 2010 and December 31, 2009, respectively.

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

At June 30, 2010 and December 31, 2009, the Company had restricted cash of $14,278,000 and $9,754,000, respectively.  The cash is restricted because it has been posted as collateral to support issued letters of credit.

6Long-term debt

Long-term debt consists of the following:

	June 30, 2010			December 31, 2009
First Lien Senior Secured Notes	$	593,936		$	586,096
Senior Notes	212,120			—
Debt issue costs and other	(41,219		)	(32,154		)
	$	764,837		$	553,942

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

On December 12, 2008, the Company entered into credit agreements pursuant to which the lenders named therein agreed to extend certain credit facilities to the Company in an aggregate principal amount of U.S.$545,000,000 (the “Bridge Loans”), the proceeds of which were to be used to provide financing for the Acquisition.

On May 27, 2009, the Company issued First Lien Senior Secured Notes (the “First Lien Notes”) in an aggregate principal amount of U.S.$560,000,000. The First Lien Notes have a 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 10.0% unsecured Senior Notes (the “Senior Notes”) in an aggregate principal amount of U.S.$200,000,000.  The Senior Notes have a term of eight years expiring on January 19, 2018, and accrue interest at 10.0% 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 11.3%, and 11.4% for the three and six months ended June 30, 2010, respectively, and 10.4% and 9.9% for the three and six months ended June 30, 2009, respectively.

7Other long-term liabilities

	June 30, 2010		December 31, 2009
Remediation liabilities	$	12,948	$	13,015
Post-retirement benefits	2,751		2,642
Accrued pension liability	434		435
	$	16,133	$	16,092

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 at the refinery and further remedial action is required.

8Related 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 June 30, 2010 and 2009 were $256,000 and $257,000, respectively.  For the six months ended June 30, 2010 and 2009, the management fees were $527,000 and

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

$523,000, respectively.  These amounts are included in general and administrative expenses on the statement of income.

In October 2009, two members of senior management of the Company began serving as trustees of Palko Environmental Ltd. (“Palko”), formerly known as Deepwell Energy Services Trust and another two members of senior management began serving as members of the board of directors of Palko.  On February 1, 2010, the Company entered into an agreement with Palko, whereby the Company would provide marketing and transportation services to Palko.  For the three and six months ended June 30, 2010, the Company recognized costs of $73,000 and $3,514,000, respectively, and also recognized revenue of $27,000 and $47,000, respectively.  In addition, in the three months ended June 30, 2010, the Company participated in a private placement financing with Palko for $3.0 million that allowed the Company to maintain its approximate 39% equity interest in Palko.

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

9Income taxes

The income tax recovery 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 June 30,						Six months ended June 30,
	2010			2009			2010			2009
Income (loss) before income taxes	$	(67,319	)	$	8,524		$	(54,622	)	$	2,396
Statutory income tax rate	28.0		%	29.0		%	28.0		%	29.0		%
Computed income tax provision (recovery)	(18,849		)	2,472			(15,294		)	695
Increase (decrease) in income tax resulting from:
Unrealized foreign exchange loss	938			2,802			938			4,114
Non-taxable portion of foreign exchange loss (gain)	260			(8,898		)	(468		)	(8,898		)
Stock based compensation	345			—			690			—
Other, including revisions in previous tax estimates	(87		)	(274		)	(16		)	—
Rate reduction due to partnership deferral	(394		)	(434		)	(833		)	(1,033		)
	$	(17,787	)	$	(4,332	)	$	(14,983	)	$	(5,122	)
Income tax recovery
Current	$	1,200		$	(64	)	$	3,067		$	666
Future	(18,987		)	(4,268		)	(18,050		)	(5,788		)
	$	(17,787	)	$	(4,332	)	$	(14,983	)	$	(5,122	)
Effective income tax rate	26.4		%	(50.8		)%	27.4		%	(213.8		)%

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

10Pension plans

The table below outlines certain information related to the Company’s defined benefit pension plans and other post retirement benefits (“OPRB”) at June 30, 2010. Additional information is contained in Note 17 of the Company’s audited consolidated financial statements as at December 31, 2009 and for the year ended December 31, 2009.

The periodic expense for the benefits is as follows:

	Three months ended June 30,
	2010					2009
	Defined benefit			OPRB		Defined benefit			OPRB
Current service cost	$	44		$	52	$	37		$	70
Interest cost	142			42		140			42
Actual return on plan assets	(148		)	—		—			—
Difference between actual and:
Expected return on plan assets	—			—		(127		)	—
Recognized actuarial gain (loss)	—			—		28			2
Difference between amortization of past service costs and actual plan amendments	26			—		—			—
Defined benefit plan expense	$	64		$	94	$	78		$	114

	Six months ended June 30,
	2010					2009
	Defined benefit			OPRB		Defined benefit			OPRB
Current service cost	$	88		$	104	$	68		$	120
Interest cost	284			84		283			87
Actual return on plan assets	(296		)	—		—			—
Difference between actual and:
Expected return on plan assets	—			—		(255		)	—
Recognized actuarial gain (loss)	—			—		55			4
Difference between amortization of past service costs and actual plan amendments	52			—		7			(31		)
Defined benefit plan expense	$	128		$	188	$	158		$	180

11Stock 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 June 30, 2010, the Company has only issued stock options to employees

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

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 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 compensation expense charged to operations was $1,260,000 and $2,410,000 in the three and six months ended June 30, 2010, respectively. There was no expense in the three and six  months ended June 30, 2009 as the plan was not in effect until the third quarter of 2009. The Company records stock based compensation on a separate expense line item in its statement of income as all of the awards are considered to be corporate expenses and classified as general and administrative expenses.

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, 2009	5,189	54,550		$	1,000
Cancellation	819	(819	)	1,000
Balance at June 30, 2010	6,008	53,731		$	1,000

No options were granted in the three and six months ended June 30, 2010. At June 30, 2010, total outstanding options vested under the Plan were 9,546 at a weighted-average exercise price of $1,000.

12Financial instruments

The Company has financial instruments other than financial contracts consisting of cash and cash equivalents, accounts receivable, loan to equity investee, accounts payable, and long-term debt. With the exception of long-term debt and the loan to equity investee, the carrying value of these instruments approximates fair market value due to the relatively short period to maturity or the interest rates attached to the instruments. Long-term debt is carried at amortized cost using the effective interest method of amortization. The estimated fair market value of long-term debt at June 30, 2010, based on market information, was U.S.$794,800,000. The loan to equity investee is an amount due to a related party with no fixed terms of repayment, the fair value of which is not readily determinable.

The fair value of financial assets and liabilities were as follows:

			June 30, 2010		December 31, 2009
Financial Assets
	Held for Trading	Risk Management Assets	$	1,270	$	752
Financial Liabilities
	Held for Trading	Risk Management Liabilities	$	2,793	$	3,565

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Fair value measures

The Company’s derivative instruments consist of financially settled commodity futures, options, swap contracts and foreign currency forward contracts. 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 derivative 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 derivative contracts at June 30, 2010 was:

	Total		Level 1		Level 2		Level 3
Assets from commodity derivative contracts
Commodity futures	$	928	$	928	$	—	$	—
Commodity swaps	342		266		76		—
Total assets	$	1,270	$	1,194	$	76	$	—
Liabilities from commodity derivative contracts
Commodity swaps	$	340	$	—	$	340	$	—
AESO electricity swap	1,675		—		1,675		—
Foreign currency forward contracts	778		—		778		—
Total liabilities	$	2,793	$	—	$	2,793	$	—

The following is a summary of the Company’s risk management contracts outstanding, along with their carrying value and fair value at June 30, 2010:

Crude Oil & Crude Oil Related Risk Management

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”).

WTI Futures

Term	Contract	Volume (Contracts)bbls	Weighted Average U.S.$/unit		Fair Value
July 2010 – December 2010	Bought Futures	86	$	78.15
July 2010 – December 2010	Sold Futures	427	78.38
					$	928

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

ClearPort-WTI Swap

Term	Contract	Volumebbls	U.S.$/bbl		Fair Value
January 2011 – December 2011	Sold Fixed Price	5	$	83.77
					$	266

ClearPort-Mt. Belvieu Propane Swaps

Term	Contract	Volumebbls	U.S.$/bbl		Fair Value
January 2011 – April 2011	Bought Fixed Price	10	40.95
					$	76
May 2011 – December 2011	Bought Fixed Price	10	$	40.95
October 2010 – December 2010	Bought Fixed Price	10	$	48.93
					$	(311	)

ClearPort-Conway Propane Swap

Term	Contract	Volumebbls	U.S.$/bbl		Fair Value
October 2010 – December 2010	Bought Fixed Price	5	$	42.84
					$	(29	)

Foreign Currency Exchange Rate Risk Management

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.

USD Forwards

Term	Contract	Volume U.S.$	Weighted average exchange rate(CAD$/U.S.$)		Fair value
July 9, 2010	Forward sell	2,100	$	1.0505
July 26, 2010	Forward sell	22,550	1.0380
July 28, 2010	Forward sell	7,700	1.0390		$	(778	)

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Electricity Risk Management

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
July 1, 2010 – December 31, 2012	Bought Fixed Price	72	$	80.49	$	(1,675	)

Interest and commodity price risk

The Company’s net income and cash flows are subject to volatility stemming from changes in interest rates on the variable rate debt obligations and fluctuations in commodity prices of crude oil and petroleum products. The Company’s interest rate risk exposure does not exist within any of the segments, but exists at the corporate level where the variable rate debt obligations are issued. The Company uses derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices and interest rates, as well as reduce volatility of cash flows. Based on the Company’s risk management policies, all of the derivative 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 interest rates or commodity prices.

Balance sheet presentation of derivative financial instruments

The fair values of derivative financial instruments in the Company’s balance sheet were as follows:

	June 30,2010			December 31, 2009
Current
Accounts receivable	$	1,270		$	752
Accounts payable and accrued charges	(2,793		)	(3,565		)
	$	(1,523	)	$	(2,813	)

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Financial Risk Factors

The Company’s activities expose it to certain financial risks, including currency risk, fair value interest rate risk, cash flow interest risk and 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 derivatives have not been designated as hedges. No speculative positions are entered into by the Company.

(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. Prior to the issuance of the First Lien Notes, the long-term debt was a floating rate loan.  However, the First Lien Notes issued accrue interest at a fixed rate of 11.75% per annum and the Senior Notes accrue interest at a fixed rate of 10.0% per annum. Under the Liquidity 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.

(c) Commodity price risk

The Company is exposed to changes in the price of oil, oil related products, gas and electricity commodities and these are monitored regularly. Oil and gas price futures, options and swaps are used to manage the exposure to oil and gas price movements. These derivatives are not designated as hedges. An electricity price swap is used to manage the exposure to electricity prices in Canada and is marked to market each period.

(d) Credit risk

The Company’s credit risk arises from its outstanding accounts 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. Allowance for doubtful accounts was $904,000 and $386,000 at June 30, 2010 and December 31, 2009, respectively.  At June 30, 2010 and December 31, 2009, approximately 2.3% and 2.4% of trade receivables are past due but are not considered to be impaired. The maximum exposure to credit risk related to accounts receivable is their carrying value, as disclosed in the financial statements.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

The Company establishes guidelines for customer credit limits and terms. The Company provides adequate provisions for expected losses from the credit risks associated with trade accounts 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 derivative 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, with investment grade credit ratings as determined by recognized credit rating agencies, or commodity brokers with respect to crude oil options and swaps.

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 as conditions change. Sufficient funds and the Liquidity Facility are available to satisfy both the Company’s long and short-term requirements. The Liquidity Facility totals U.S.$150,000,000 and at June 30, 2010 and December 31, 2009 there was $28,731,000 and $25,000,000 drawn against the facility, respectively.

Set out below is maturity analyses of certain of the Company’s financial liabilities as at June 30, 2010. 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 two and five years		After five years		Total
Liquidity Facility	$	28,731	$	—	$	—	$	28,731
Accounts payable and accrued charges	317,386		—		—		317,386
Long-term debt	—		593,936		212,120		806,056
Accrued interest on long-term debt	15,564		—		—		15,564
Total financial liabilities	$	361,681	$	593,936	$	212,120	$	1,167,737

(f) Sensitivity analysis

The following sensitivity analysis is intended to illustrate the sensitivity to changes in market variables on the Company’s financial instruments and show the impact on profit or loss and shareholders’ equity. Financial instruments affected by market risk include borrowings, deposits and derivative financial instruments. The sensitivity analysis relates to the position as at June 30, 2010. The analysis excludes the impact of movements in market variables on the carrying value of pension and other post retirement obligations.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

In calculating the sensitivity analysis, it has been assumed that the carrying values of financial assets and liabilities carried at amortized cost do not change as interest rates change.

Commodity price sensitivity

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. Changes in commodity prices could have resulted in the following unrealized gains (losses) impacting net income as of June 30, 2010.

	Favorable 15% Change		Unfavorable 15% Change
Crude oil related prices	$	2,163	$	(2,163	)

	Favorable 10% Change		Unfavorable 10% Change
Electricity prices	$	252	$	(252	)

The movements in the statement of income arise from changes in the fair value of light crude oil futures and swaps, natural gasoline swaps, butane swaps and propane swaps as a result of changes in the crude oil price. These instruments have not been designated in a hedge relationship, but will offset future transactions.

Foreign currency exchange rate sensitivity

At June 30, 2010, if the Canadian dollar strengthened or weakened by 5%, relative to the U.S. dollar, the impact on net income would be as follows:

	Favorable 5% Change		Unfavorable 5% Change
USD Forwards	$	1,165	$	(1,165	)
Long-term debt	34,660		(34,660		)

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 Liquidity Facility and working capital. To maintain or adjust the capital structure, the Company may raise debt or equity and/or adjust its capital spending to manage its current and projected debt levels.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

The terms of the Liquidity 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 June 30, 2010, this covenant is not applicable.

Additionally, the terms of the First Lien Notes and Senior Notes limit the Company’s ability to incur certain additional indebtedness or to make certain acquisitions unless the Company meets or exceeds a consolidated interest coverage ratio.  At June 30, 2010, the Company did not meet this ratio.

13Contingencies

Two subsidiaries of the Company are currently undergoing various 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, Hunting has indemnified the Company for the pre-closing period impact of these audits.  Included in income tax receivable as at June 30, 2010 is $34,821,000, whereby Hunting paid the Company and the Company paid the tax assessments relative to these audits.

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.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

14Segmental 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 moving oil 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 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 NGL marketing business.  The retail operations sell propane to residential and industrial 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, wellsite fluids, tops, and roofing flux.

Marketing includes the purchasing, selling, storing, and blending of crude oil, condensate and natural gas, taking advantage of specific location, quality, or time based arbitrage opportunities and enhancing the overall profitability of its operations.

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.

In 2010, the Company re-evaluated how it internally manages its business and, in turn, made changes within the operating segments. More specifically, the Company realigned the operations of the NGL marketing business and the frac plant from the marketing and terminals and pipelines segments, respectively, to the propane and NGL marketing and distribution segment. As a result, historical segment information has been revised to align with the new operating 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.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Three months endedJune 30, 2010	Marketing			Truck Transportation			Terminals & Pipelines			Propane & NGL Marketing & Distribution			Processing & Wellsite Fluids			Corporate & other reconciling balances			Total
Statement of income
Revenue - external and inter-segmental	$	707,147		$	80,509		$	230,207		$	142,014		$	85,928		$	—		$	1,245,805
Revenue - inter-segmental	(111,541		)	(10,201		)	(219,963		)	(29,091		)	(26,965		)	—			(397,761		)
Revenue - external	595,606			70,308			10,244			112,923			58,963			—			848,044
Cost of product & service – external & inter-segmental	706,965			52,997			217,805			129,206			78,331			—			1,185,304
Operating and other costs	2,955			16,190			5,041			8,743			6,747			—			39,676
Cost of product & service – inter-segmental	(111,541		)	(10,201		)	(219,963		)	(29,091		)	(26,965		)	—			(397,761		)
Cost of sales-external	598,379			58,986			2,883			108,858			58,113			—			827,219
	(2,773		)	11,322			7,361			4,065			850			—			20,825
Foreign exchange loss (gain)	(702		)	(8		)	—			7			277			—			(426		)
Loss on sale of assets	—			22			—			—			—			—			22
Loss (gain) from investment in associates	—			—			(29		)	83			—			—			54
Segmental operating profit	(2,071		)	11,308			7,390			3,975			573			—			21,175
Depreciation of property, plant and equipment	507			5,519			6,031			1,814			1,493			646			16,010
Amortization of intangible assets	169			2,549			600			1,474			2,352			—			7,144
General and administrative	—			—			—			—			—			6,270			6,270
Stock based compensation	—			—			—			—			—			1,260			1,260
Accretion expense	—			—			—			—			—			193			193
Foreign exchange loss	—			—			—			—			—			32,873			32,873
Interest expense	—			—			—			—			—			24,806			24,806
Interest income	—			—			—			—			—			(62		)	(62		)
Income tax recovery	—			—			—			—			—			(17,787		)	(17,787		)
Net income (loss)	$	(2,747	)	$	3,240		$	759		$	687		$	(3,272	)	$	(48,199	)	$	(49,532	)
Non-current assets
Property, plant and equipment	$	34,327		$	147,936		$	276,112		$	80,853		$	88,292		$	14,715		$	642,235
Goodwill	43,555			48,457			199,969			93,216			117,664			—			502,861
Intangible assets	3,956			81,401			19,307			34,958			34,315			—			173,937
Other segmental items
Capital expenditures:
Property, plant and equipment	—			5,338			2,002			1,828			3,287			718			13,173
Intangible assets	—			38,129			1,512			13,371			—			—			53,012
Goodwill	—			40,286			1,587			15,647			—			—			57,520
Total assets	290,937			333,447			522,365			314,243			315,078			124,657			1,900,727

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Three months endedJune 30, 2009	Marketing			Truck Transportation			Terminals & Pipelines			Propane & NGL Marketing & Distribution			Processing & Wellsite Fluids			Corporate & other reconciling balances			Total
Statement of income
Revenue - external and inter-segmental	$	734,338		$	56,144		$	122,703		$	67,579		$	68,689		$	—		$	1,049,453
Revenue - inter-segmental	(63,558		)	(6,071		)	(110,648		)	(22,786		)	(25,952		)	—			(229,015		)
Revenue - external	670,780			50,073			12,055			44,793			42,737			—			820,438
Cost of product & service – external & inter-segmental	729,921			36,992			104,078			55,901			61,994			—			988,886
Operating and other costs	2,856			11,978			5,373			8,219			5,509			—			33,935
Cost of product & service – inter-segmental	(63,558		)	(6,071		)	(110,648		)	(22,786		)	(25,952		)	—			(229,015		)
Cost of sales-external	669,219			42,899			(1,197		)	41,334			41,551			—			793,806
	1,561			7,174			13,252			3,459			1,186			—			26,632
Foreign exchange loss (gain)	(382		)	2			—			158			(589		)	—			(811		)
Loss (gain) on sale of assets	—			68			—			(7		)	—			—			61
Loss from investment in associates	—			—			3			105			—			—			108
Segmental operating profit	1,943			7,104			13,249			3,203			1,775			—			27,274
Depreciation of property, plant and equipment	439			4,659			5,022			1,293			1,443			500			13,356
Amortization of intangible assets	168			2,438			564			906			2,346			—			6,422
General and administrative	—			—			—			—			—			9,610			9,610
Accretion expense	—			—			—			—			—			116			116
Foreign exchange gain	—			—			—			—			—			(49,924		)	(49,924		)
Debt extinguishment costs	—			—			—			—			—			18,517			18,517
Interest expense	—			—			—			—			—			20,758			20,758
Interest income	—			—			—			—			—			(105		)	(105		)
Income tax recovery	—			—			—			—			—			(4,332		)	(4,332		)
Net income (loss)	$	1,336		$	7		$	7,663		$	1,004		$	(2,014	)	$	4,860		$	12,856
Non-current assets
Property, plant and equipment	$	35,051		$	114,711		$	279,065		$	66,455		$	83,058		$	15,399		$	593,739
Goodwill	43,555			90,490			198,343			68,787			117,664			—			518,839
Intangible assets	4,630			73,556			20,055			25,587			43,720			—			167,548
Other segmental items
Capital expenditures:
Property, plant and equipment	82			2,526			628			786			2,070			696			6,788
Intangible assets	—			1,950			—			—			—			—			1,950
Goodwill	—			707			—			—			—			—			707
Total assets	311,978			347,853			510,595			206,544			317,042			93,013			1,787,025

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Six months endedJune 30, 2010	Marketing			Truck Transportation			Terminals & Pipelines			Propane & NGL Marketing & Distribution			Processing & Wellsite Fluids			Corporate & other reconciling balances			Total
Statement of income
Revenue - external and inter-segmental	$	1,577,583		$	146,521		$	512,374		$	316,187		$	206,388		$	—		$	2,759,053
Revenue - inter-segmental	(313,951		)	(26,166		)	(490,693		)	(61,122		)	(54,840		)	—			(946,772		)
Revenue - external	1,263,632			120,355			21,681			255,065			151,548			—			1,812,281
Cost of product & service – external & inter-segmental	1,571,181			96,861			485,351			279,510			186,057			—			2,618,960
Operating and other costs	6,051			28,803			10,985			18,823			10,648			—			75,310
Cost of product & service – inter-segmental	(313,951		)	(26,166		)	(490,693		)	(61,122		)	(54,840		)	—			(946,772		)
Cost of sales-external	1,263,281			99,498			5,643			237,211			141,865			—			1,747,498
	351			20,857			16,038			17,854			9,683			—			64,783
Foreign exchange loss (gain)	(187		)	(8		)	—			606			(32		)	—			379
Loss (gain) on sale of assets	—			11			—			16			(1		)	—			26
Loss from investment in associates	—			—			360			198			—			—			558
Segmental operating profit	538			20,854			15,678			17,034			9,716			—			63,820
Depreciation of property, plant and equipment	991			9,438			11,774			3,381			2,991			1,329			29,904
Amortization of intangible assets	338			4,332			1,169			2,439			4,704			—			12,982
Stock based compensation	—			—			—			—			—			2,410			2,410
General and administrative	—			—			—			—			—			12,508			12,508
Accretion expense	—			—			—			—			—			393			393
Foreign exchange loss	—			—			—			—			—			11,799			11,799
Interest expense	—			—			—			—			—			48,724			48,724
Interest income	—			—			—			—			—			(278		)	(278		)
Income tax recovery	—			—			—			—			—			(14,983		)	(14,983		)
Net income (loss)	$	(791	)	$	7,084		$	2,735		$	11,214		$	2,021		$	(61,902	)	$	(39,639	)
Non-current assets
Property, plant and equipment	$	34,327		$	147,936		$	276,112		$	80,853		$	88,292		$	14,715		$	642,235
Goodwill	43,555			48,457			199,969			93,216			117,664			—			502,861
Intangible assets	3,956			81,401			19,307			34,958			34,315			—			173,937
Other segmental items
Capital expenditures:
Property, plant and equipment	95			5,611			4,576			5,311			4,257			1,324			21,174
Intangible assets	—			45,816			1,512			14,293			—			—			61,621
Goodwill	—			46,430			1,587			16,507			—			—			64,524
Total assets	290,937			333,447			522,365			314,243			315,078			124,657			1,900,727

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Six months endedJune 30, 2009	Marketing			Truck Transportation			Terminals & Pipelines			Propane & NGL Marketing & Distribution			Processing & Wellsite Fluids			Corporate & other reconciling balances			Total
Statement of income
Revenue - external and inter-segmental	$	1,292,631		$	114,978		$	226,188		$	243,425		$	140,897		$	—		$	2,018,119
Revenue - inter-segmental	(119,431		)	(12,461		)	(198,082		)	(49,597		)	(48,277		)	—			(427,848		)
Revenue - external	1,173,200			102,517			28,106			193,828			92,620			—			1,590,271
Cost of product & service — external & inter-segmental	1,271,699			76,457			190,572			200,514			119,912			—			1,859,154
Operating and other costs	5,305			23,791			12,975			18,337			8,847			—			69,255
Cost of product & service — inter-segmental	(119,431		)	(12,461		)	(198,082		)	(49,597		)	(48,277		)	—			(427,848		)
Cost of sales-external	1,157,573			87,787			5,465			169,254			80,482			—			1,500,561
	15,627			14,730			22,641			24,574			12,138			—			89,710
Foreign exchange loss (gain)	590			—			(1		)	1,163			(760		)	—			992
Loss (gain) on sale of assets	—			68			—			(7		)	—			—			61
Loss from investment in associates	—			—			80			206			—			—			286
Segmental operating profit	15,037			14,662			22,562			23,212			12,898			—			88,371
Depreciation of property, plant and equipment	981			8,814			11,150			2,731			2,748			1,243			27,667
Amortization of intangible assets	336			4,811			1,128			1,812			4,692			—			12,779
General and administrative	—			—			—			—			—			15,452			15,452
Accretion expense	—			—			—			—			—			229			229
Foreign exchange gain	—			—			—			—			—			(30,569		)	(30,569		)
Debt extinguishment costs	—			—			—			—			—			18,517			18,517
Interest expense	—			—			—			—			—			42,097			42,097
Interest income	—			—			—			—			—			(197		)	(197		)
Income tax recovery	—			—			—			—			—			(5,122		)	(5,122		)
Net income	$	13,720		$	1,037		$	10,284		$	18,669		$	5,458		$	(41,650	)	$	7,518
Non-current assets
Property, plant and equipment	$	35,051		$	114,711		$	279,065		$	66,455		$	83,058		$	15,399		$	593,739
Goodwill	43,555			90,490			198,343			68,787			117,664			—			518,839
Intangible assets	4,630			73,556			20,055			25,587			43,720			—			167,548
Other segmental items
Capital expenditures:
Property, plant and equipment	465			4,737			1,797			2,058			3,093			1,100			13,250
Intangible assets	—			1,950			—			—			—			—			1,950
Goodwill	—			707			—			—			—			—			707
Total assets	311,978			347,853			510,595			206,544			317,042			93,013			1,787,025

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

Geographic Data

Based on the location of the end user, approximately 18% and 16% of revenue was to customers in the United States for the three and six months ended June 30, 2010, respectively. The Company did not have any significant revenues outside of Canada in the three and six months ended June 30, 2009.

The Company’s long lived assets are primarily concentrated in Canada with 12% in the United States at June 30, 2010. The Company did not have any material long lived assets outside of Canada at December 31, 2009.

15United States accounting principles and reporting

The consolidated financial statements have been prepared in accordance with Canadian GAAP. The application of U.S. GAAP would have the following effects on net income (loss), comprehensive income (loss) and shareholder’s equity as reported (in thousands, except share data):

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Net income (loss) - Canadian GAAP	$	(49,532	)	$	12,856		$	(39,639	)	$	7,518
Capitalized interest (a)	278			(5		)	534			209
Business combinations (b)	(2,359		)	(155		)	(2,401		)	(155		)
Tax impact of the above adjustments	583			47			523			(16		)
Net income (loss) — U.S. GAAP	(51,030		)	12,743			(40,983		)	7,556
Other comprehensive income (loss), net of tax
Pensions and post-retirement benefits (c)	—			402			—			(1,291		)
Foreign currency translation adjustment	4,175			—			4,175			—
Comprehensive income (loss) — U.S. GAAP	(46,855		)	13,145			(36,808		)	6,265
Shareholder’s equity
Balance, beginning of the period — U.S. GAAP	482,097			532,131			474,271			542,011
Net income (loss) — U.S. GAAP	(51,030		)	12,743			(40,983		)	7,556
Pensions and post retirement benefits (c)	—			402			—			(1,291		)
Stock based compensation	1,260			—			2,410			—
Foreign currency translation adjustment	4,175			—			4,175			—
Accretion of preferred shares (d)	(3,411		)	(3,000		)	(6,782		)	(6,000		)
Balance, end of period — U.S. GAAP	433,091			542,276			433,091			542,276
Accumulated other comprehensive income (loss)
Balance, beginning of the period — U.S. GAAP	(1,429		)	(1,693		)	(1,429		)	—
Foreign currency translation adjustment	4,175			—			4,175			—
Pension and post-retirement benefits (c)	—			402			—			(1,291		)
Balance, end of period — U.S. GAAP	$	2,746		$	(1,291	)	$	2,746		$	(1,291	)

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

	June 30,2010			December 31, 2009
Shareholder’s Equity
Shareholder’s equity — Canadian GAAP	$	555,590		$	588,644
Increase (decrease) in shareholders equity under U.S. GAAP
Capitalized interest (a)	816			282
Business combinations (b)	(2,556		)	(155		)
Pension and post-retirement benefits (c)	(2,013		)	(2,013		)
Tax impact of the above changes	1,070			547
Reclassification of preferred shares as temporary equity (mezzanine) (d)	(119,816		)	(113,034		)
Shareholder’s equity — U.S. GAAP	$	433,091		$	474,271

[a] Capitalized interest

Under Canadian GAAP, capitalization of interest during the construction of qualifying assets is an acceptable, but not mandatory, accounting policy, if the related indebtedness is attributable to the acquisition, construction or development of the qualifying assets.  Under U.S. GAAP, capitalization of interest is required for certain qualifying assets that require a period of time to get them ready for their intended use. No interest was capitalized for qualifying assets by the Company in the consolidated financial statements prepared in accordance with Canadian GAAP during any of the periods presented.  Under U.S. GAAP, interest capitalized was $278,000 and $534,000 for the three and six months ended June 30, 2010 and $(5,000) and $209,000 for the three and six months ended June 30, 2009, respectively, net of amortization of $10,000 and $11,000, respectively. As of June 30, 2010, the total accumulated adjustment to U.S. GAAP retained earnings was $816,000.

[b] Business combinations

Under Canadian GAAP, the purchase price of an acquisition includes direct costs incurred by the acquirer, such as finder’s fees, advisory, legal, accounting, valuation, other professional or consulting fees, and general and administrative costs. Under U.S. GAAP, the Company adopted guidance such that effective January 1, 2009 direct costs are expensed in the periods which they are incurred.

During the three and six months ended June 30, 2010, the Company incurred $2,359,000 and $2,401,000 of direct costs of a business combination that were capitalized under Canadian GAAP that would not be capitalized under U.S. GAAP. There was $155,000 of direct costs of a business combination incurred in the three and six months ended June 30, 2009. As of June 30, 2010, the total accumulated adjustment to U.S. GAAP retained earnings was $2,556,000.

[c] Pension and other post-retirement liability

Under Canadian GAAP, the funding status of pension and other post retirement benefit plans are not required to be recognized on the balance sheet. Under U.S. GAAP, the over-funded or under-funded status of the defined benefit post retirement plans are recognized on the balance sheet as an asset or liability, and changes in the funded status are recognized through comprehensive income.

As at June 30, 2010, the total cumulative adjustments to liabilities and accumulated other comprehensive income was $1,429,000, net of tax.

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

[d] Temporary equity (mezzanine)

Under U.S. GAAP such preferred shares are classified as temporary equity (mezzanine) outside of shareholders equity, which generates an accounting difference between Canadian and U.S. GAAP.  Additionally, under Canadian GAAP, accrued dividends are recognized for each period as a reduction of the Company’s retained earnings and increase in carrying value of the preferred shares.  For U.S. GAAP purposes, accretion of the mezzanine financing amount resulted in an additional U.S. GAAP difference equal to the amount of dividends accreted during the period.

[e] Consolidated Statement of Cash flow

There are no material differences between the Consolidated Statement of Cash Flows under U.S. GAAP and Canadian GAAP.

[f] U.S. GAAP Disclosures

In addition to the disclosure contained in the consolidated financial statements, the following additional disclosures are required under U.S. GAAP:

Debt issuance costs

Under Canadian GAAP, the Company made an accounting policy selection to record long-term debt net of debt issuance costs. Under U.S. GAAP, debt issuance costs are recorded in other assets. As a result, the impact under U.S. GAAP is to reclassify debt issuance costs of $41,219,000 and $32,154,000 from long-term debt to other long term assets on the balance sheet at June 30, 2010 and December 31, 2009, respectively.

Realized and unrealized gains (losses) on derivatives

Under Canadian GAAP, realized and unrealized gains (losses) on derivatives that are not accounted for as hedges are classified within revenues and cost of sales, the detailed components of which are presented in the table below. Under U.S. GAAP such realized and unrealized gains (losses) would be classified as “other income (expense)” in the statement of income.

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Revenues
Realized gains	$	—		$	9,882		$	—		$	44,591
Unrealized gains	(9		)	(12,453		)	435			2,394
Realized losses	(9		)	(374		)	(73		)	(1,084		)
Unrealized losses	(803		)	(861		)	(1,475		)	(47,394		)
	$	(821	)	$	(3,806	)	$	(1,113	)	$	(1,493	)
Cost of sales
Realized gains	$	9,535		$	4,694		$	11,603		$	21,594
Unrealized gains	1,028			(228		)	4,808			51,113
Realized losses	(3,862		)	(24,132		)	(7,447		)	(62,306		)
Unrealized losses	1,770			7,544			(2,478		)	(20,123		)
	8,471			(12,122		)	6,486			(9,722		)
Total net effect	$	7,650		$	(15,928	)	$	5,373		$	(11,215	)

Gibson Energy Holding ULC

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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

[g] New Accounting Pronouncements — U.S. GAAP

In June 2009, the FASB issued guidance to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The guidance is effective for financial statements issued for interim and annual periods beginning on or after November 15, 2009.  The Company adopted the guidance on January 1, 2010 and it did not have an impact on the consolidated financial position, results of operations or cash flows.

In June 2009, the FASB issued guidance to improve financial reporting by enterprises involved with variable interest entities. This guidance amends previous guidance and requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity. The guidance is effective for financial statements issued for interim and annual periods beginning on or after November 15, 2009. The Company adopted the guidance on January 1, 2010 and it did not have an impact on the consolidated financial position, results of operations or cash flows.

In January 2010, the FASB issued guidance to improve disclosures relating to fair value measurements. This guidance requires additional disclosures and requires a gross presentation of activities within the Level 3 roll forward. This guidance is effective for interim and annual periods beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim periods within those years. We adopted the guidance on January 1, 2010. Our adoption did not have any material impact on our financial position, results of operations, or cash flows. We will adopt the guidance that will be effective for annual periods beginning after December 15, 2010 on January 1, 2011. We do not expect that adoption of this guidance will have any material impact on our financial position, results of operations, or cash flows.

16Subsequent Events

On August 25, 2010, the Company completed the acquisition of the remaining 75% equity interest in Battle River Terminal ULC (“BRT”) for approximately $55.0 million in cash. Prior to the acquisition, the Company had a 25% ownership interest in BRT, which was accounted for under the equity method of accounting.  BRT is comprised of four storage tanks and related infrastructure that are connected to the Company’s Hardisty Terminal, with each storage tank having a capacity of 300,000 barrels.

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

RThe following information should be read in conjunction with our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2010 and 2009 and our audited consolidated financial statements and related notes for the year ended December 31, 2009, the period from December 13, 2008 to December 31, 2008, the period from January 1, 2008 to December 12, 2008 and the year ended December 31, 2007, which were prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”), which differ in some material respects from generally accepted accounting principles of the United States of America (“U.S. GAAP”). For a discussion of the principal differences between Canadian GAAP and U.S. GAAP applicable to the Company, see note 15 to our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2010 and 2009 and note 25 to our audited consolidated financial statements.

On December 12, 2008, Gibson Acquisition ULC, an Alberta unlimited liability corporation (“Gibson AcquisitionCo”), an indirect wholly owned subsidiary of R/C Guitar Cooperatief U.A., a Dutch co-op (“Co-op”) owned by investment funds affiliated with Riverstone Holdings LLC (“Riverstone” or the “Sponsor”), acquired all of the issued and outstanding Class A Common Shares and Class B Common Shares (the “Acquisition”) of Gibson Energy Holdings Inc. Following the Acquisition, Gibson Energy Holdings Inc. was converted into an unlimited liability corporation and through several amalgamations, was amalgamated with Gibson AcquisitionCo to form the surviving amalgamated unlimited liability corporation, Gibson Energy ULC, a wholly owned subsidiary of Gibson Energy Holding ULC. The audited consolidated financial statements present separately the periods prior to the Acquisition (“Predecessor”) and the periods after the Acquisition (“Successor”) to recognize the application of a different basis of accounting. To facilitate the discussion of the comparative periods, management presents certain financial information on a combined basis in addition to the separate Predecessor and Successor periods. The combined financial information does not comply with Canadian GAAP or U.S. GAAP and does not purport either to represent actual results or to be indicative of results we might achieve in future periods.

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 June 30, 2010, its results of operations for the three and six months ended June 30, 2010 and 2009, and its cash flows for the three and six months ended June 30, 2010 and 2009. The condensed consolidated balance sheet data as of December 31, 2009 was derived from our audited consolidated financial statements. The unaudited condensed consolidated financial statements do not include all disclosures required by Canadian GAAP or U.S. 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 year ended December 31, 2010. 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 Registration Statement on Form F-4, as filed with the Securities and Exchange Commission (“SEC”) on April 26, 2010. 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 the United States and are engaged in the transportation, storage, blending, processing, marketing and distribution of crude oil, condensate, NGLs such as propane and butane, refined products and natural gas. This business is typically referred to as the midstream energy business. Through our extensive network of integrated assets in western Canada and the United States, we move hydrocarbon products to market utilizing our terminals, pipelines, tank storage and truck transportation fleet, which, in concert with our processing, blending and marketing capabilities, provide valuable services to both producers and consumers. We participate across the full midstream energy value chain, from the producing regions in western Canada, through our strategically located terminals in Hardisty and Edmonton, to the refineries of North America via major pipelines serving the region. We have provided market access to the energy industry in western Canada over the last 56 years and believe we are a critical component to the future

development of the substantial resources in the Western Canada Sedimentary Basin (“WCSB”), one of the most hydrocarbon-rich regions in the world.

Since 1953, we have consistently been a leader in the western Canadian midstream energy market, developing and maintaining strong relationships with the leading industry participants. Since that time, our business has grown by expanding both geographically and by diversifying our service offerings to meet new customer needs.

We manage our operations through five operating segments: (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 diversified, high-value fixed asset base, geographic presence in one of the most hydrocarbon-rich basins in the world, strategic footholds in key markets and our conservative risk management policies. We are continuously focused on improving our operations across all segments by lowering costs, utilizing our integrated asset base to capture inter-segment synergies and expanding our network of assets, as well as increasing our margins by providing additional value-adding services along the midstream energy chain. In the first quarter of 2010, we re-evaluated how we internally manage our business and, in turn, made changes within our operating segments. More specifically, we realigned the operations of our NGL marketing business and the operations of our frac plant from the marketing and terminals and pipelines segments, respectively, to the propane and NGL marketing and distribution segment. As a result, historical segment information has been revised to align with the new operating segments.

Highlights

The key highlights of the six months ended June 30, 2010, compared to the six months ended June 30, 2009, were:

·We completed the acquisition of 100% of the equity of Taylor Companies LLC and substantially all the assets of Taylor Propane Gas Inc. (collectively “Taylor”) for approximately $153.1 million. Taylor is an independent for-hire crude oil transportation, logistics and crude oil and NGL marketing business with operations and facilities, including pipeline injection stations, in most crude oil producing states in the United States. This acquisition expands our presence as a premier North American midstream company;

·On January 19, 2010, we issued 10.0% Senior Notes due 2018 (“Senior Notes”) in an aggregate principal amount of U.S.$200.0 million. In addition, we also entered into an amendment to our liquidity facility to increase the total borrowing capacity for revolving loans and letters of credit in an aggregate principal amount of up to U.S.$150.0 million;

·Revenue increased 14% and cost of sales increased 16%, primarily due to global commodity price increases;

·The truck transportation segment showed an increase in segment profit, but total segment profit declined by 28%, due to declines in our other operating segments;

·Net loss was $39.6 million in the six months ended June 30, 2010 compared to a net income of $7.5 million in the six months ended June 30, 2009. The decrease was primarily due to foreign exchange losses on our long-term debt in the six months ended June 30, 2010 compared to foreign exchange gains on our long-term debt in the six months ended June 30, 2009. The decrease was also due to the decline in our overall segment profit and increased interest expense.

·We completed the acquisition of Johnstone Tank Trucking Ltd. (“Johnstone”) for approximately $21.3 million, expanding our market presence in the Southwest area of Saskatchewan. We also completed the acquisition of Aarcam Propane & Construction Heat Ltd. (“Aarcam”), a propane business located in Calgary, Alberta, for approximately $3.4 million.

·We participated in a private placement financing with Deepwell Energy Services Trust (“Deepwell”) for $3.0 million that allowed us to maintain our approximate 39% equity interest in Deepwell, and provided Deepwell with the financing to complete its acquisition of the remaining interest in Palko Energy Ltd., further expanding its interests in the Bakken area of Southeast Saskatchewan. In addition, Deepwell converted to a corporation and combined with Palko Energy Ltd. to form Palko Environmental Ltd. (“Palko”).

On August 25, 2010, the Company completed the acquisition of the remaining 75% equity interest in Battle River Terminal ULC (“BRT”) for approximately $55.0 million in cash. BRT is comprised of four storage tanks and related infrastructure,

with each storage tank having a capacity of 300,000 barrels.  The storage tanks are connected to our Hardisty Terminal and can deliver crude oil directly to the Keystone pipeline or to the Enbridge or Express pipeline systems.

Trends affecting our business

In accordance with our long-range strategic plan we are continuously evaluating organic growth opportunities and potential acquisitions of transportation, gathering, terminalling or storage and other complementary midstream businesses. Most recently, we completed the acquisition of Taylor, an independent for-hire crude oil transportation, logistics and crude oil and NGL marketing business in the United States. Although we believe we are well situated in the Canadian and United States midstream industry, we face various operational, regulatory, financial and competitive challenges that may impact our ability to execute our strategy as planned.

With the volatility in crude oil prices, tightened price differentials between crude oil streams and blending agents, volatile financial markets, a slower than expected recovery from a global recession and tightening of available credit, we face challenges in the short term with respect to maintaining operating margins, managing our inventory positions and gaining access to credit with our trading partners. We believe we can overcome these challenges by following prudent commodity risk management programs and maintaining our liquidity. At June 30, 2010, we had unrestricted cash of $24.7 million and $109.3 million available under our liquidity facility of U.S.$150.0 million, with outstanding letters of credit of $21.1 million. Due to the synergistic, integrated nature of our business and the focus of our services being mainly towards production related activities, we are optimistic that we will be able to meet our short term objectives.

We operate in a mature industry and believe that acquisitions will play an important role in our future growth. These acquisition efforts often involve assets that, if acquired, could have a material effect on our financial condition and results of operations and may divert management’s attention from the daily operation of the business. We also continuously evaluate opportunities that will allow us to expand both geographically and by diversifying our service offerings. These opportunities will leverage our knowledge base and skill sets, allowing us to participate in other energy related businesses or geographic areas that have characteristics and opportunities similar to, or that otherwise complement, our existing activities.

While we believe we will have sufficient cash flow from operations to fund most of our planned growth and that we may have access to additional capital from Riverstone or the capital markets should we require additional funds, we can give no assurance that funds will be available on acceptable terms, or at all. Additionally, while we expect the acquisitions we make to be accretive in the long term, we can give no assurance that our current or future acquisition efforts will be successful, that any such acquisition will be completed on terms considered favorable to us, or at all, or that our expectations will ultimately be realized.

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:

·Continued overall depletion of conventional North American crude oil production;

·New technology and drilling methodology being deployed towards conventional production within the WCSB;

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

·Increased crude oil production from the WCSB, including from the Canadian oil sands; and

·Expansion of the midstream infrastructure in the WCSB to handle increased production and expansion of capacity in the U.S. refining complex to handle heavier crude oil from the 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. In an environment of tight supply and demand balances, even relatively minor supply disruptions can cause significant price swings. Conversely, despite a relatively balanced market on a global basis, competition within a given region of North America could cause downward pricing pressure and significantly impact

regional crude oil price differentials among crude oil grades and locations. Although we believe our business strategy is designed to manage these trends, factors and potential developments, and that we are strategically positioned to benefit from certain of these developments, there can be no assurance that we will not be negatively affected.

Acquisitions and internal growth projects

We completed a number of acquisitions and capital expansion projects in the six months ended June 30, 2010 and 2009. The following table summarizes our capital expenditures for internal growth projects, acquisitions and upgrade and replacement capital (in thousands):

	Six months ended June 30,
	2010		2009
Internal growth projects	$	13,646	$	5,695
Acquisitions, including equity investments	180,826		6,900
Upgrade and replacement capital(1)	7,528		7,555
	$	202,000	$	20,150

(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.

Internal growth projects

In the six months ended June 30, 2010, our internal growth projects included: the continued expansion of our Canwest truck fleet and tankage; building a new tank at the Edmonton South Terminal; the expansion of our truck transportation fleet and the expansion of capacity and construction of a new tank at the Moose Jaw Refinery.

The following table summarizes our key projects undertaken in the six months ended June 30, 2010 and 2009 (in thousands):

	Six months ended June 30,
	2010		2009
Canwest fleet and tank expansion(1)	$	1,706	$	1,198
Edmonton South Terminal storage tank construction(2)	1,355		—
Moose Jaw capacity expansion(3)	2,633		719
Purchase of land(4)	1,601		—
Truck transportation trailer fleet expansion(5)	2,604		916
Rail loading rack at Edmonton South Terminal(6)	1,851		—
Frac fluid recycling facility(7)	—		1,439
Other growth projects(8)	1,896		1,423
Total	$	13,646	$	5,695

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

(2)Represents capital spent to build a tank at our Edmonton South Terminal. Total spend on the tank as of June 30, 2010 was$2.8 million.

(3)      ��                        Represents expenditure incurred in the expansion of capacity and the building of a new tank at the Moose Jaw Refinery.

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

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

(6)Represents capital spent to build a rail loading rack at our Edmonton South Terminal.

(7)Represents capital spent to construct a frac fluid recycling and reclamation facility. This facility became operational during the year ended December 31, 2009 for a total project cost of approximately $7.8 million.

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

Acquisitions, including equity investments

In the six months ended June 30, 2010, we completed a number of acquisitions including the acquisitions of Taylor for aggregate consideration of $153.1 million, effective May 14, 2010;  Johnstone for aggregate consideration of $21.3 million, effective January 31, 2010; and, 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. In addition, we participated in a private placement with Palko for $3.0 million, thereby allowing us to maintain our 39% equity interest.

Seasonality

Although certain activities in our business segments are seasonal, in general, seasonality does not have a material impact on our combined operations and segments.

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 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 oilpatch-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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of consolidated financial statements in conformity with Canadian GAAP 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 Registration Statement on Form F-4, which was filed with the SEC on April 26, 2010. We believe there have been no significant changes during the six months ended June 30, 2010 to the items that we disclosed in our critical accounting policies and estimates.

Changes in accounting policies

The Company did not adopt any new accounting policies in the six months ended June 30, 2010.

Recent accounting pronouncements

We have assessed new and revised accounting pronouncements that have been issued but are not yet adopted and determined that the following may have an impact on the Company:

a) Business Combinations

The CICA issued Handbook Section 1582 Business Combinations, which replaces Section 1581. This new standard is effective for business combinations entered into on or after January 1, 2011 and affects the accounting and related expenses

incurred at the date a business combination closes. The adoption of the revised standard is expected to impact our financial statements only to the extent that business combinations are entered into after the effective date.

b) Consolidated Financial Statements

The CICA issued Handbook Section 1601 Consolidated Financial Statements that discusses consolidation accounting following a business combination that involves a purchase of an equity interest by one company in another. This new standard is effective for fiscal years beginning on or after January 1, 2011. We are currently in the process of evaluating the new standard and have not yet determined its impact on our financial statements.

International Financial Reporting Standards

The Canadian Accounting Standards Board has announced that accounting standards in Canada, as used by public companies, will be converged to International Financial Reporting Standards (“IFRS”) effective January 1, 2011. We will convert to these new standards according to the timetable set with these new rules. The changeover date is for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011.

We are currently executing a changeover plan to complete the transition by January 1, 2011, including preparing the required 2010 comparative information. We are on schedule with our changeover plan. We expect that the adoption of IFRS will not have a major impact on our operations or strategic decisions.

As of June 30, 2010, we have made significant progress on the changeover plan. We have analyzed our accounting policy alternatives and we expect that we will finalize our IFRS accounting policies in the latter half of 2010. We will also continue to update our IFRS changeover plan to reflect new and amended accounting standards issued by the International Accounting Standards Board. Process and system changes have been reviewed for significant areas of impact, including reviewing the process to capture the required 2010 IFRS comparative data. IFRS education and training sessions have been held internally and these sessions will continue throughout 2010.

Based on the status of the project to date, we believe that the significant areas of impact include property, plant and equipment, asset retirement obligations, business combinations, impairment testing, employee benefit plans and income taxes.  However, the quantification of the impact has not been finalized as we continue to work through finalizing our IFRS accounting policies and calculations.

New Accounting Pronouncements—U.S. GAAP

Information about new accounting pronouncements under U.S. GAAP are included in Note 15 of our condensed consolidated financial statements for the three and six months ended June 30, 2010 and 2009.

RESULTS OF OPERATIONS

The following is a discussion of our results of operations for the three and six months ended June 30, 2010 and 2009, and the following table sets forth our consolidated statements of operations for those periods:

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	(in thousands)
Revenue
Products	$	755,903		$	749,166		$	1,637,631		$	1,445,406
Services	92,141			71,272			174,650			144,865
Total Revenues	848,044			820,438			1,812,281			1,590,271
Cost of sales, excluding depreciation and amortization
Cost of products	772,493			743,572			1,633,509			1,397,369
Cost of services	54,726			50,234			113,989			103,192
Total cost of sales, excluding depreciation and amortization	827,219			793,806			1,747,498			1,500,561
	20,825			26,632			64,783			89,710
Operating expenses
Depreciation of property, plant and equipment	16,010			13,356			29,904			27,667
General and administrative	6,270			9,610			12,508			15,452
Amortization of intangible assets	7,144			6,422			12,982			12,779
Stock based compensation	1,260			—			2,410			—
Loss on sale of property, plant and equipment	22			61			26			61
Other non-operating expenses (income)
Accretion expense	193			116			393			229
Foreign exchange loss (gain)	32,447			(50,735		)	12,178			(29,577		)
Debt extinguishment costs	—			18,517			—			18,517
Loss from investment in associates	54			108			558			286
Interest expense (income)
Long-term debt	24,340			20,598			47,791			41,808
Income	(62		)	(105		)	(278		)	(197		)
Other	466			160			933			289
	88,144			18,108			119,405			87,314
Income (loss) before income taxes	(67,319		)	8,524			(54,622		)	2,396
Income tax recovery	(17,787		)	(4,332		)	(14,983		)	(5,122		)
Net income (loss)	$	(49,532	)	$	12,856		$	(39,639	)	$	7,518

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, 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.

Revenue and profit by segment for the three and six months ended June 30, 2010 and 2009 were as follows:

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	(in thousands)
Segment revenue
Terminals and pipelines	$	230,207		$	122,703		$	512,374		$	226,188
Truck transportation	80,509			56,144			146,521			114,978
Propane and NGL marketing and distribution	142,014			67,579			316,187			243,425
Processing and wellsite fluids	85,928			68,689			206,388			140,897
Marketing	707,147			734,338			1,577,583			1,292,631
Total segment revenue	1,245,805			1,049,453			2,759,053			2,018,119
Revenue—inter-segmental	(397,761		)	(229,015		)	(946,772		)	(427,848		)
Total Revenue—external	848,044			820,438			1,812,281			1,590,271
Segment profit (loss)
Terminals and pipelines	7,390			13,249			15,678			22,562
Truck transportation	11,308			7,104			20,854			14,662
Propane and NGL marketing and distribution	3,975			3,203			17,034			23,212
Processing and wellsite fluids	573			1,775			9,716			12,898
Marketing	(2,071		)	1,943			538			15,037
Total segment profit	21,175			27,274			63,820			88,371
General and administrative	6,270			9,610			12,508			15,452
Depreciation and amortization	23,154			19,778			42,886			40,446
Stock based compensation	1,260			—			2,410			—
Accretion expense	193			116			393			229
Foreign exchange loss (gain)	32,873			(49,924		)	11,799			(30,569		)
Debt extinguishment costs	—			18,517			—			18,517
Interest expense, net	24,744			20,653			48,446			41,900
Income (loss) before income tax	(67,319		)	8,524			(54,622		)	2,396
Income tax recovery	(17,787		)	(4,332		)	(14,983		)	(5,122		)
Net income (loss)	$	(49,532	)	$	12,856		$	(39,639	)	$	7,518

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 trailers, 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

We provide tariff-based pipeline services and fee-based storage and terminalling services for crude oil, condensate and refined products through 245 miles of pipeline, two major storage terminals strategically located at Edmonton and Hardisty, which are the principal hubs for moving oil products out of the WCSB, 11 custom blending terminals (of which seven have custom blending activities including the Edmonton South Terminal), all of which are strategically located throughout Alberta and Saskatchewan and 71 pipeline injection stations located in the United States, primarily in Louisiana, Texas, Oklahoma, Wyoming, Montana and North Dakota.

Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. Tariffs at the terminals depend upon product density, volume, demand for terminalling, terms of the contract and available tankage. In addition to pipeline

receipts, crude and condensate are trucked into all terminals. The Edmonton South Terminal has pipeline receipts from  Suncor’s Edmonton and Fort McMurray refineries. The Hardisty Terminal has receipts from the Company-owned Bellshill and Provost pipelines, and receipt and delivery connections to most major pipelines in the area.

The segment profit generated by our tariff and other fee-related activities is dependent on the volumes transported through our pipelines and the level of the tariff and other fees charged as well as the fixed and variable field costs of operating the pipeline. The segment profit generated at our terminals depends upon the level of throughput, fees related to condensate blending, and the ability to recover the cost of dedicated tankage and earn a return on that tankage. The operating expenses of our terminals and pipelines are largely fixed and are comprised of operational payroll, maintenance and repairs, structural integrity management and fees for utilities. Some variable costs within the operating expenses are directly chargeable to larger customers with longer term contracts and dedicated tankage.

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

	Three months ended June 30,		Six months ended June 30,
Volumes (barrels in thousands)	2010	2009	2010	2009
Custom terminals	2,837	2,106	6,129	4,324
Injection stations	4,211	—	4,211	—
Hardisty	16,087	17,729	30,657	34,729
Edmonton South	5,032	3,992	8,791	7,911
Total terminals	21,119	21,721	39,448	42,640
Bellshill	480	776	964	1,565
Provost	1,656	1,761	3,374	3,584
Total pipelines	2,136	2,537	4,338	5,149

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)
Revenues	$	230,207	$	122,703	$	512,374	226,188
Cost of sales	217,805		104,078		485,351		190,572
Operating expenses and other	5,012		5,376		11,345		13,054
Segment Profit	$	7,390	$	13,249	$	15,678	$	22,562

Three months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

Custom terminal volumes increased 35% in the three months ended June 30, 2010, compared to the three months ended June 30, 2009, mainly as a result of  increased throughput at the terminals. As a result of the increase in volumes and the overall increase in average prices for crude oil and condensate, revenues increased by approximately $107.5 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, which also resulted in a corresponding increase in cost of sales.

As part of the acquisition of 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. Revenue is charged based on volumes that run through the injection stations and was $0.5 million for the three months ended June 30, 2010.

Hardisty Terminal volumes decreased 9% in the three months ended June 30, 2010, compared to the three months ended June 30, 2009 as a result of lower volumes from the Athabasca pipeline and from other pipeline sources. The decrease in volumes was also due to the unfavorable market dynamics for blending, which was due to narrow pricing differentials between crude types. Overall revenues declined by $1.3 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009.

Edmonton South Terminal volumes increased 26% in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, largely as a result of an increase in crude volumes, which was largely driven by the increase in volumes from our marketing segment and an increase in diesel shipments through the terminal from a major customer. These diesel shipments are subject to minimum volume charges. Revenues at Edmonton South increased by $1.0 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, as a result of the increase in crude volumes. In addition, revenue from our diesel terminalling contracts remained relatively stable because they are all fixed fee below a certain minimum volume.

Volumes for our Bellshill pipeline were 38% lower in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, due to a natural decline in receipts from the oil production batteries that produce into the pipeline and reduced volumes being moved into the pipeline as a result of unfavorable market dynamics for blending. The decrease in volumes resulted in a $0.2 million decrease in revenues in the three months ended June 30, 2010 compared to the three months ended June 30, 2009.

Due to natural declines for batteries connected to the pipeline, volumes for our Provost pipeline also declined by 6% in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. Tariff increases, however, led to revenue remaining relatively stable in the three months ended June 30, 2010 compared to the three months ended June 30, 2009.

Operating expenses and other.  Overall operating expenses and other costs decreased by $0.4 million, or 7%. The decrease was related to the decrease in the unrealized loss recorded in connection with our electricity hedge in the three months ended June 30, 2010 compared to June 30, 2009. The movement in the unrealized amount was $0.6 million and $0.2 million in the three months ended June 30, 2010 and 2009, respectively. Other operating costs remained relatively stable.

Segment profit.  Overall, segment profit in the three months ended June 30, 2010 decreased by $5.9 million, or 44%, compared to the three months ended June 30, 2009. The primary reason for the decrease was due to lower profits being generated from our custom terminals and at our Hardisty Terminal, offset by increased profits from our Edmonton South Terminal.

Six months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

Custom terminal volumes increased 42% in the six months ended June 30, 2010, compared to the six months ended June 30, 2009, mainly as a result of increased throughput at the terminals. As a result of the increase in volumes and the overall increase in average prices for crude oil and condensate, revenues increased by approximately $285.6 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, which also resulted in a corresponding increase in cost of sales.

As part of the acquisition of 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. Revenue is charged based on volumes that run through the injection stations and was $0.5 million for the six months ended June 30, 2010.

Hardisty Terminal volumes decreased 12% in the six months ended June 30, 2010, compared to the six months ended June 30, 2009 as a result of lower volumes from the Athabasca pipeline and from other pipeline sources. The decrease in volumes was also due to the unfavorable market dynamics for blending, which was due to narrow pricing differentials between crude types. Overall revenues declined $1.3 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Edmonton South Terminal volumes increased 11% in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, largely as a result of an increase in crude volumes, which was largely driven by the increase in volumes from our marketing segment offset by lower diesel shipments through the terminal from a major customer, which are subject to minimum volume charges. Revenues at Edmonton South increased by $1.8 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, as a result of the increase in crude volumes. In addition, revenue from our diesel terminalling contracts remained relatively stable because they are all fixed fee below a certain minimum volume.

Volumes for our Bellshill pipeline were 38% lower in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, due to a natural decline in receipts from the oil production batteries that produce into the pipeline and reduced volumes being moved into the pipeline as a result of unfavorable market dynamics for blending. The decrease in volumes resulted in a $0.5 million decrease in revenues in the six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Due to natural declines for batteries connected to the pipeline, volumes for our Provost pipeline also declined by 6% in the six months ended June 30, 2010 compared to the six months ended June 30, 2009. Tariff increases, however, led to revenue increasing by $0.1 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Operating expenses and other.  Overall operating expenses and other costs decreased by $1.7 million, or 13%. The decrease was related to the decrease in the unrealized loss recorded in connection with our electricity hedge in the six months ended June 30, 2010 of $0.4 million compared to an increase in the unrealized loss amount of $1.4 million in the six months ended June 30, 2009. Other operating costs remained relatively stable.

Segment profit.  Overall, segment profit in the six months ended June 30, 2010 decreased by $6.9 million, or 30%, compared to the six months ended June 30, 2009. The primary reason for the decrease was due to lower profits being generated from our custom terminals, offset by increased profits from our Edmonton South Terminal.

Truck transportation

We offer hauling services for crude, condensate, propane, butane, asphalt, methanol, sulfur, petroleum coke, gypsum and drilling fluids to oil and gas producers primarily in western Canada and the United States. We also generate revenues from the sale of chemicals to the natural gas processing industry.

Transportation rates can vary based on receipt point, delivery point, length of haul and product hauled. In addition, hauls can be regularly scheduled under service agreements or hauled as spot movements. The truck transportation segment profit depends on the volumes transported through the fleet, the billing rates charged, the payment made to carriers and the net hauling margin available to cover the direct operating costs of maintaining the fleet, along with our indirect operating costs of general and administrative overhead.

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

	Three months ended June 30,		Six months ended June 30,
Volumes (barrels in thousands)	2010	2009	2010	2009
Barrels hauled	32,253	19,075	58,155	41,462

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)
Revenues	$	80,509	$	56,144	$	146,521	$	114,978
Cost of sales	52,997		36,992		96,861		76,457
Operating expenses and other	16,204		12,048		28,806		23,859
Segment profit	$	11,308	$	7,104	$	20,854	$	14,662

Three months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

For the three months ended June 30, 2010, barrels hauled increased by 69% compared to the three months ended June 30, 2009, due mainly to the impact of the acquisitions of Taylor, which occurred on May 14, 2010; Johnstone, which occurred on January 31, 2010; and, Bridge Creek, which occurred on May 1, 2009. In addition, hauling volumes also increased, particularly the hauling of petroleum coke due to an overall increase in demand in the industry for the product.

Revenues increased by 43% in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, mainly as a result of the acquisitions of Taylor, Johnstone and Bridge Creek.

Cost of sales is primarily comprised of payments to owner operators. Cost of sales in the three months ended June 30, 2010 increased 43%,  in line with the increase in revenue, as compared to the three months ended June 30, 2009.

Operating expenses and other.  Overall operating expenses and other costs increased by $4.2 million, or 34%, in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, mainly due to the impact of additional costs related to increased activity levels derived from the Taylor, Johnstone and Bridge Creek acquisitions.

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

Six months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

For the six months ended June 30, 2010, barrels hauled increased by 40% compared to the six months ended June 30, 2009, due mainly to the impact of the acquisitions of Taylor, which occurred on May 14, 2010; Johnstone, which occurred on January 31, 2010; and, Bridge Creek, which occurred on May 1, 2009. In addition, hauling volumes, particularly in crude and condensate and petroleum coke also increased. Hauling of crude and condensate increased mainly due to the impact of adding a new major customer in the fourth quarter of 2009. Hauling of petroleum coke increased due to an overall increase in demand in the industry for the product.

Revenues increased by 27% in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, mainly as a result of the acquisitions of Taylor, Johnstone and Bridge Creek and also due to increased overall hauling volume.

Cost of sales is primarily comprised of payments to owner operators. Cost of sales in the six months ended June 30, 2010 increased 27%, in line with the increase in revenue, as compared to the six months ended June 30, 2009.

Operating expenses and other.  Overall operating expenses and other costs increased by $4.9 million, or 21%, in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, mainly due to the impact of additional costs related to increased activity levels derived from the Taylor, Bridge Creek and Johnstone acquisitions.

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

Propane and NGL marketing and distribution

We are the second largest retail propane distribution company in Canada and also operate a wholesale business that includes a propane distribution and NGL marketing business. We sold over 61 million gallons during 2009 to retail, residential and industrial customers throughout western Canada and over 205 million gallons of wholesale propane volumes during 2009. We also provide marketing services for NGL products to our customers and also operate an NGL marketing business as part of our recent acquisition of Taylor. Included in our NGL marketing business is a fractionation plant at our Hardisty terminal that operates as a processing facility and processes NGLs into lighter density products such as condensate, butane, propane, ethane and solvents.

Propane sales are categorized according to final usage of the propane at the point of sale. Propane pricing in both the wholesale and retail markets is heavily dependent on the market pricing of propane, which forms the cost of sales, known as the “rack price.” Rack price is the price at which the product is offered for sale at the production plant, typically a natural gas processing plant or a refinery. Rack price is dependent on product supply and demand, weather, location differentials, as well as transportation and storage costs. Retail propane is price sensitive to the rack price and margin per gallon changes can impact the ability to meet the fixed costs such as maintaining the fleet and administration. Wholesale propane and NGL marketing sales are usually much larger volumes and generally have lower per gallon or barrel margins than retail propane. Wholesale propane and NGL marketing are also impacted more by spot market pricing and arbitrage opportunities. Where possible, longer-term contracts with market indexed prices are signed with larger customers. Wholesale fixed price contracts are backed with inventory of propane to minimize margin exposure. Other product-retail is comprised of parts and equipment sales. Other income is comprised of service labor, rentals and delivery charges, which form part of our ancillary services through our branch offices.

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

	Three months ended June 30,		Six months ended June 30,
Volumes	2010	2009	2010	2009
Sales volumes—retail (gallons in thousands)
Residential	668	708	2,334	2,856
Oilpatch	6,891	4,909	17,617	13,280
Commercial and industrial	2,094	2,130	7,319	8,829
Automotive	1,970	2,156	3,330	3,638
Other	1,060	1,022	2,305	2,319
	12,683	10,925	32,905	30,922
Sales volumes—wholesale
Propane distribution (gallons in thousands)	33,130	34,563	95,209	105,746
NGL Marketing (barrels in thousands)
Propane	—	48	41	80
Butane	375	134	666	250
Condensate	287	334	615	765
Taylor	664	—	664	—
	1,326	516	1,986	1,095

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)
Revenues
Retail
Propane	$	20,815	$	16,285	$	62,745	$	54,838
Other	548		614		1,107		1,377
Total retail	21,363		16,899		63,852		56,215
Wholesale
Propane distribution	34,764		27,318		118,117		108,322
NGL Marketing	83,561		21,651		128,701		74,127
Total wholesale	118,325		48,969		246,818		182,449
Other income	2,326		1,711		5,517		4,761
Total revenues	142,014		67,579		316,187		243,425
Cost of sales
Retail
Propane	13,837		9,403		43,637		33,891
Other	363		453		793		1,102
Total retail	14,200		9,856		44,430		34,993
Wholesale
Propane distribution	33,204		25,213		110,098		98,352
NGL Marketing	81,802		20,832		124,982		67,169
Total wholesale	115,006		46,045		235,080		165,521
Total cost of sales	129,206		55,901		279,510		200,514
	12,808		11,678		36,677		42,911
Operating expenses and other	8,833		8,475		19,643		19,699
Segment profit	$	3,975	$	3,203	$	17,034	$	23,212

Three months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

Retail volumes increased 16% in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, largely as a result of increased volumes in the oilpatch market. The increase in the oilpatch market was as a result of an overall increase in drilling activity in the three months ended June 30, 2010 compared to the three months ended June 30, 2009.  The increase was offset by small declines in all the other markets.  In particular, declines were experienced in the residential market due to warmer weather conditions in our key markets and in the commercial and industrial markets due to declines in construction activity and 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 26% in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, primarily as a result of increased rack prices and also due to increased sales volumes.

Wholesale propane distribution volumes decreased by 4% in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, due to lower demand as a result of warmer weather in the current year period. However, revenues increased by 27%, as a result of increased rack prices.

NGL marketing volumes increased 157% in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, 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 which was due to a decrease in demand from our marketing segment. NGL marketing revenues increased 286% due mainly to the impact of the additional revenue from the Taylor acquisition.

Cost of sales per gallon in retail propane and wholesale propane distribution increased 27% and 37%, respectively, in the three months ended June 30, 2010, due to increased rack prices. Retail propane margin per gallon decreased by 13% as a result of a change in the overall sales mix, as oilpatch sales contributed a higher percentage of total sales but have lower margins than other retail markets.   Wholesale propane distribution margin per gallon was lower in the three months ended June 30, 2010 compared to the three months ended June 30, 2009 by 23%. This decrease was largely due to less favourable pricing conditions in the three months ended June 30, 2010 compared to the three months ended June 30, 2009.

Cost of sales for NGL marketing increased 293% in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, largely due to the impact of the Taylor acquisition in the three months ended June 30, 2010.

Operating expenses and other.  Overall operating expenses and other costs increased by $0.4 million, or 4%, in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, primarily due to an increase in payroll related expenses.

Segment profit.  The propane and NGL marketing and distribution segment profit increased in the three months ended June 30, 2010 by $0.8 million or 24% as compared to the three months ended June 30, 2009 primarily as a result of increased margins in our NGL marketing offset by increased operating expenses.

Six months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

Retail volumes increased 6% in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, largely as a result of increased volumes in the oilpatch market. The increase in the oilpatch market was as a result of an overall increase in drilling activity in the six months ended June 30, 2010 compared to the six months ended June 30, 2009.  The increase was offset by declines in all the other markets.  In particular, declines were experienced in the residential market due to warmer weather conditions in our key markets and in the commercial and industrial markets due to declines in construction activity and 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 14% in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, primarily as a result of increased rack prices and increased sales volumes.

Wholesale propane distribution volumes decreased by 10% in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, due to lower demand as a result of warmer weather in the current year period. However, revenues increased by 9%, as a result of increased rack prices.

NGL marketing volumes increased 81% in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, 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 which was due to a decrease in demand from our marketing segment. NGL marketing revenues increased 74% due mainly to the impact of the Taylor acquisition.

Cost of sales per gallon in retail propane and wholesale propane distribution increased 21% and 24%, respectively, in the six months ended June 30, 2010, due to increased rack prices. Retail propane margin per gallon decreased by 14% as a result of a change in the overall sales mix, as oilpatch sales contributed a higher percentage of total sales but have lower margins than other retail markets.   Wholesale propane distribution margin per gallon was lower in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 by 11%. This decrease was largely due to less favourable pricing conditions in the six months ended June 30, 2010 compared to the six months ended June 30, 2009. In particular, wide differentials in the Puget Sound region existed in the first quarter of 2009, but similar conditions did not exist in the six months ended June 30, 2010.

Cost of sales for NGL marketing increased 86% in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, largely due to the impact of the Taylor acquisition.

Operating expenses and other.  Overall operating expenses and other costs remained relatively stable and only decreased by $0.1 million in the six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Segment profit.  The propane and NGL marketing and distribution segment profit decreased in the six months ended June 30, 2010 by $6.2 million or 27% as compared to the six months ended June 30, 2009 primarily as a result of lower margins in both retail and wholesale propane distribution and also in NGL marketing, especially in the first three months of 2010 as compared to the first three months of 2009.

Processing and wellsite fluids

Our processing and wellsite fluids segment is centered around a refinery with a capacity of approximately 16,000 barrels per day located at Moose Jaw, Saskatchewan. We refine and market a variety of products, including several grades of road asphalt, roofing flux, wellsite fluids and tops. Our products are shipped by truck, rail and pipeline from Saskatchewan to markets in the U.S. and Canada. Currently, the refinery at Moose Jaw processes barrels of heavy crude oil received from two independent pipelines.

We are dependent on the availability of a supply of heavy crude oil and the demand for the various products processed from crude oil. For all products except tops, sales prices are dependent on market pricing and the availability of competing product. For tops, the sales price is determined relative to a local sour crude oil stream.

Cost of sales, or crude costs, for all products depends on availability of product, base price for the crude, and the differential between WTI and the specific grade of crude being processed. Cost of sales also includes processing costs that are capitalized and recognized when products are sold. These costs include costs directly related to the refinery operations including natural gas, electricity, operations labor and other general costs.

Operating expenses include general maintenance, marketing and sales and salaries and benefits related to office personnel.

The market demand for road asphalt is dependent on competitive pricing, the weather being amenable to paving and the approval of government spending for road construction and repair. The market demand for roofing flux asphalt is dependent on product quality, competitive pricing and the market demand for roofing shingle products in the U.S.

Wellsite fluids, including distillate, frac fluid, and solvent are largely produced at Moose Jaw and sold to external customers. We also have a frac fluid reprocessing service business, whereby we recycle used frac fluids and return the used fluids to a new reusable product. The wellsite fluids sales market is dependent on overall well drilling activity in our market areas, the availability of competing product, and the specific end use of the product.

The cost of sales of our wellsite fluids product are mainly the costs incurred by the refinery at Moose Jaw to produce our products and the margin is dependent upon transportation costs and marketing and sales efforts. Operating expenses include payroll and related costs, as well as general and administrative costs.

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

	Three months ended June 30,		Six months ended June 30,
Volumes (barrels in thousands)	2010	2009	2010	2009
Roofing flux	331	326	726	718
Road asphalt	138	136	246	163
Frac fluid	47	17	242	90
Tops	364	363	717	760
Distillate	79	44	266	200
Other	8	8	16	14
Total sales volumes	967	894	2,213	1,945

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)
Revenues
Road asphalt and roofing flux	$	43,222	$	35,732	$	83,627	$	63,145
Frac fluid	4,988		3,144		28,539		10,656
Tops	26,956		23,983		54,817		43,557
Distillate	9,974		5,111		37,639		21,986
Other	788		719		1,766		1,553
Total revenues	85,928		68,689		206,388		140,897
Cost of sales	78,331		61,994		186,057		119,912
Operating expenses and other	7,024		4,920		10,615		8,087
Segment profit	$	573	$	1,775	$	9,716	$	12,898

Three months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

Sales volumes for roofing flux and road asphalt increased 2% in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. Road asphalt sales volume remained relatively flat as the paving season in both 2010 and 2009 was delayed due to cold wet weather. Roofing flux volume also remained relatively stable. Road asphalt and roofing flux revenue increased by 21% in the three months ended June 30, 2010 compared to the three months ended June 30, 2009 due to an increase in average asphalt prices.

Frac fluid volumes increased 176% in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. This increase was primarily due to increased market demand for the product due to a general increase in activity levels, including increased drilling activity in the WCSB. Frac fluid revenues were 59% higher in the three months ended June 30, 2010 compared to the three months ended June 30, 2009, which was attributable to higher volumes. The increase in revenue was lower than the increase in volume due to an increase in customer recycled frac volumes, which have lower selling prices compared to other frac fluids.

Tops volumes remained relatively stable in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009. However, tops revenues were 12% higher over the same period, reflecting the higher price of crude oil, which is the basis for pricing tops.

Sales volumes for distillate were 80% higher in the three months ended June 30, 2010 compared to the three months ended June 30, 2009 due to an increase in drilling activity. Distillate revenues were 95% higher in the period as a result of higher distillate prices and higher volumes.

The overall cost per barrel for the basket of products sold by the processing and wellsite segment increased by 17% due to increased crude costs.

Overall margins increased by $0.9 million, or 13%, in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009. The primary reason for the increase in overall margins was due to the increase in margins from our wellsite fluid products, which was due to increased overall demand. Offset against this was lower asphalt margins, which was negatively impacted by higher prices of crude oil, and Tops margins, which was due to narrow grade differentials.

Operating expenses and other.  Operating expenses increased by $2.1 million or 43% in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, primarily due to increased maintenance expenses in the current year period and also the impact of a foreign exchange loss of $0.3 million in the three months ended June 30, 2010 compared to a foreign exchange gain of $0.6 million in the three months ended June 30, 2009.

Segment profit.  The processing and wellsite fluids segment profit decreased in the three months ended June 30, 2010 by $1.2 million, or 68% as compared to the three months ended June 30, 2009 primarily as a result of the increase in operating expenses offset by an increase in overall margins.

Six months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

Sales volumes for roofing flux and road asphalt increased 10% in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 largely driven by increases in road asphalt. Road asphalt sales volume increased mainly in the first quarter of 2010 as a result of customers purchasing in advance of the paving season to secure volumes and to take advantage of winter fill pricing, which we sold at lower pricing in order to be able to produce at levels to meet our wellsite fluid demand. Roofing flux volume remained relatively stable. Road asphalt and roofing flux revenue increased by 32% in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 largely due to an increase in average asphalt prices and also due to the increase in volumes.

Frac fluid revenues were 168% higher in the six months ended June 30, 2010 compared to the six months ended June 30, 2009, which was attributable to higher volumes. Frac fluid volumes increased 169% in the six months ended June 30, 2010 compared to the six months ended June 30, 2009. This increase was primarily due to increased market demand for the product due to a general increase in activity levels, including increased drilling activity in the WCSB.

Tops volumes were 6% lower in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. The decrease in volume is a result of an increase in volumes of our frac fluid and distillate. When frac fluid and distillate volumes decline, we can move the light volume product volume as Tops. However, Tops revenues were 26% higher over the same period, reflecting the higher price of crude oil, which is the basis for pricing tops.

Sales volumes for distillate were 33% higher in the six months ended June 30, 2010 compared to the six months ended June 30, 2009 due to an increase in drilling activity. Distillate revenues were 71% higher in the period as a result of higher distillate prices and higher volumes.

The overall cost per barrel for the basket of products sold by the processing and wellsite segment increased by 37% due to increased crude costs as discussed above.

Overall margins decreased by $0.7 million, or 3%, in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. The primary reason for the decrease in overall margins was largely related to the higher price of crude oil, which negatively impacted our asphalt margins, and Tops margins, which was due to narrow grade differentials. Offset against this was an increase in margins for our wellsite fluids, which was a result of increased overall demand.

Operating expenses and other.  Operating expenses increased by $2.5 million or 31% in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, primarily due to an increase in maintenance expenses and also due to a foreign exchange gain of $0.8 million in the six months ended June 30, 2009 compared to an approximate breakeven foreign exchange charge in the six months ended June 30, 2010.

Segment profit.  The processing and wellsite fluids segment profit decreased in the six months ended June 30, 2010 by $3.2 million or 25% as compared to the six months ended June 30, 2009 primarily as a result of a decrease in overall margins for road asphalt and roofing flux and also due to the increase in operating expenses.

Marketing

Leveraging our extensive infrastructure and asset network, we provide valuable marketing services to our customers. In serving these customer needs, we purchase, sell, store, and blend approximately 169,000 boe per day of crude oil, condensate and natural gas, taking advantage of specific location, quality, or time based arbitrage opportunities designed to enhance the overall profitability of our operations. Certain of these factors are outside of our control and such factors cause increased volatility in the margins earned by this segment. The marketing segment is also responsible for managing price risk associated with our physical commodity positions, based on the needs of each operating segment.

Our revenues from marketing activities reflect the sale of gathered and bulk-purchased crude oil, refined products and LPG volumes. These revenues also include the sale of additional barrels exchanged through arrangements entered into to supplement the margins of gathered and bulk-purchased volumes. Because the commodities that we buy and sell are generally indexed to the same pricing indices for both the purchase and the sale, revenues and costs related to purchases will increase and decrease with changes in market prices. However, the margins related to those purchases and sales will not necessarily have corresponding increases and decreases. We do not anticipate that future changes in volumes or revenues will be a primary driver of segment profit. Generally, we expect our segment profit to increase or decrease directionally with increases or decreases in pricing volatility between various crude oil types and strength or weakness of market conditions relative to the demand for blending services as well as the allocation of our assets among our various risk management strategies. In particular, in periods where price differentials between crude oil streams and blending agents are wide, our opportunity to profit by capturing spreads is enhanced, and in periods where such price differentials are tighter, our opportunity to profit is reduced. In addition, the execution of our risk management strategies in conjunction with our storage facilities can provide upside in certain markets.

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

	Three months ended June 30,		Six months ended June 30,
Volumes (barrels in thousands)	2010	2009	2010	2009
Sales Volumes
Crude and diluent	11,184	12,054	22,808	22,781
Natural gas (GJ)	8,207	27,124	18,669	45,846

	Three months ended June 30,					Six months ended June 30,
	2010			2009		2010		2009
	(in thousands)
Revenues
Crude and diluent	$	594,729		$	554,514	$	1,293,938	$	948,234
Natural gas	38,498			113,961		95,805		223,625
Edmonton North	73,920			65,863		187,840		120,772
Total revenues	707,147			734,338		1,577,583		1,292,631
Cost of sales	706,965			729,921		1,571,181		1,271,699
Operating expenses and other	2,253			2,474		5,864		5,895
Segment profit (loss)	$	(2,071	)	$	1,943	$	538	$	15,037

Three months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

The crude oil market has experienced high volatility in both overall commodity price and pricing basis between various grades of crude oil. The monthly average NYMEX benchmark price of crude oil ranged from approximately $74.12 to $84.58 during the three months ended June 30, 2010 and from approximately $49.95 to $69.70 during the three months ended June 30, 2009.

Sales volumes for crude and diluent decreased by 7% in the three months ended June 30, 2010, but revenues increased by 7% due to higher commodity prices in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009. Revenues and sales volumes of crude oil varied as a result of the level of our trading activity within the various mainline pipeline systems. We refer to these trading activities as “stream sales.” Since these sales are done on low per barrel margins, revenues and volumes do not necessarily correlate closely with segment profits.

Natural gas sales volumes decreased 70% in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009, primarily due to the expiration and non-renewal of gas contracts since June 30, 2009 as we are currently winding down our natural gas marketing business. As a result, natural gas revenues were 66% lower in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009.

Cost of sales in the three months ended June 30, 2010 was 3% lower than in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. This was mainly attributable to the decrease in natural gas volumes, offset by an increase in the prices at which we were able to purchase product.

Operating expenses and other.  Operating expenses decreased by $0.2 million in the three months ended June 30, 2010 compared to the three months ended June 30, 2009. The decrease was mainly due to an increase of $0.3 million in the foreign exchange gain recorded in the three months ended June 30, 2010 compared to the three months ended June 30, 2009.

Segment profit (loss) Overall segment results decreased by approximately $4.0 million in the three months ended June 30, 2010 as compared to the three months ended June 30, 2009. The decrease in the three months ended June 30, 2010 was primarily related to the narrowing of pricing differentials between crude types in the current year period, thereby limiting our opportunity to blend crude into higher value streams. The loss in the quarter was due to a sharp decline in crude oil prices, particularly in May 2010, when the monthly average NYMEX benchmark price of crude oil declined $10.46. As prices decreased, crude oil and diluents inventory that was purchased at higher values could only be sold at current prices, thereby resulting in negative margins.

Six months ended June 30, 2010 and 2009.

Volumes, revenues and cost of sales.

The crude oil market has experienced high volatility in both overall commodity price and pricing basis between various grades of crude oil. The monthly average NYMEX benchmark price of crude oil ranged from approximately $74.12 to $84.58 during the six months ended June 30, 2010 and from approximately $39.26 to $69.70 during the six months ended June 30, 2009.

Sales volumes for crude and diluent remained relatively stable in the six months ended June 30, 2010. However, revenues for crude and diluent increased by 36% due to higher commodity prices in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. Revenues and sales volumes of crude oil varied as a result of the level of our trading activity within the various mainline pipeline systems. We refer to these trading activities as “stream sales.” Since these sales are done on low per barrel margins, revenues and volumes do not necessarily correlate closely with segment profits.

Natural gas sales volumes decreased 59% in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009, primarily due to the expiration and non-renewal of gas contracts since June 30, 2009 as we are currently winding down our natural gas marketing business. As a result, natural gas revenues were 57% lower in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009.

Cost of sales in the six months ended June 30, 2010 was 24% higher than in the six months ended June 30, 2010 compared to the six months ended June 30, 2009. This was mainly attributable to an increase in the prices at which we were able to purchase product.

Operating expenses and other.  Operating expenses remained relatively stable in the six months ended June 30, 2010 compared to the six months ended June 30, 2009. However additional costs were incurred to operate a tank from the Battle River Terminal in the six months ended June 30, 2010, as the tank did not operate in the prior year until May 2009.  These costs were offset by a decrease in foreign exchange losses recorded in the six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Segment profit.  Overall segment profit decreased by approximately $14.5 million in the six months ended June 30, 2010 as compared to the six months ended June 30, 2009. In the six months ended June 30, 2010 margins were negatively impacted by the increasing price of crude and a narrowing of the pricing differentials between crude types thereby limiting our opportunity to blend crude into higher value streams. In addition, the decrease was also due to the strong performance in the first quarter of 2009, whereby we were able to purchase inventory at relatively inexpensive values compared to market prices as several grades of crude were being discounted due either to their location or quality. We purchased this inventory and, using our truck transportation assets and terminal facilities, were able to either blend the crude into higher valued streams, creating margins, or transport the crude to locations where better sales values could be achieved. In addition, during the first six months of 2009, the WTI forward curve was in steep contango, which enabled us to realize profits on financial instruments used to price protect our inventory.

General and administrative

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 was $6.3 million and $12.5 million in the three and six months ended June 30, 2010, respectively, compared to $9.6 million and $15.5 million in the three and six months ended June 30, 2009, respectively. The decrease in G&A in the current year periods was largely related to non-recurring reorganization costs of $3.2 million incurred in the three months ended June 30, 2009.

Depreciation and amortization

Depreciation and amortization expense was $23.2 million and $42.9 million in the three and six months ended June 30, 2010, respectively, compared to $19.8 million and $40.4 million in the three and six months ended June 30, 2009, respectively.  The increase relates primarily to the additional depreciation and amortization related to our acquisitions, mainly Taylor, Johnstone and Aarcam.

Stock based compensation

Stock based compensation expense was $1.3 million and $2.4 million in the three and six months ended June 30, 2010, respectively, compared to no expense in the three and six months ended June 30, 2009. The expense in the current year periods relates to options that were granted under our equity incentive plan in the latter half of 2009. In the six months ended June 30, 2009, the equity incentive plan did not exist as it came into effect in the third quarter of 2009.

Foreign exchange loss (gain) not affecting segment profit

In the three and six months ended June 30, 2010, we recorded a foreign exchange loss of $32.9 million and $11.8 million, respectively, compared to a gain of $49.9 million and $30.6 million in the three and six months ended June 30, 2009, respectively. The loss recorded in the current year periods was due to an unfavorable movement in exchange rates related to our U.S. dollar denominated debt, as opposed to a favorable movement in exchange rates in the prior year periods.

Interest expense, net

Interest expense, net was $24.7 million and $48.4 million for the three and six months ended June 30, 2010, respectively, compared to $20.7 million and $41.9 million for the three and six months ended June 30, 2009, respectively. The increase in the current year periods was due to the increase in our outstanding long-term debt, as a result of the issuance of our Senior Notes in January, 2010.

Income tax recovery

Income tax recovery was $17.8 million and $15.0 million in the three and six months ended June 30, 2010, respectively, compared to a recovery of $4.3 million and $5.1 million in the three and six months ended June 30, 2009, respectively. The effective tax rate was 26.4% and 27.4% during the three and six months ended June 30, 2010, compared to negative effective rates of 50.8% and 213.8% during the three and six months ended June 30, 2009. The main reason for the increase in the income tax recovery in the three and six months ended June 30, 2010 compared to the prior year periods was due to losses before tax in the current year periods compared to income before tax in the prior year periods. The effective tax rate change was largely related to the impact of the non taxable portion of a realized capital gain of $61.4 million in the three and six months ended June 30, 2009.

SUMMARY OF QUARTERLY RESULTS

	Predecessor		Combined (1)		Successor
	Three months ended		Three months ended		Three months ended
	September 30, 2008		December 31, 2008		March 31, 2009			June 30, 2009		September 30, 2009		December 31, 2009			March 31, 2010		June 30, 2010
	(in thousands)
Revenues	$	1,341,529	$	899,947	$	769,833		$	820,438	$	875,164	$	988,702		$	964,237	$	848,044
Net income (loss)	10,833		16,331		(5,338		)	12,856		26,714		(97,181		)	9,893		(49,532		)
EBITDA(2)	26,901		36,756		35,879			49,060		72,065		(69,423		)	56,347		(19,359		)

(1)For comparative purposes, results for the three months ended December 31, 2008 are combined to include the Predecessor and Successor periods. The combination is not a presentation in accordance with either Canadian GAAP or U.S. GAAP. However, we believe it is a useful presentation because it allows the financial data to be analyzed across comparable periods.

(2)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 Canadian GAAP or U.S. 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 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;

·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 Canadian GAAP results and using EBITDA only supplementally. The following table reconciles net income (loss) to EBITDA:

	Predecessor		Combined (1)		Successor
	Three months ended		Three months ended		Three months ended
	September 30, 2008		December 31, 2008		March 31, 2009			June 30, 2009			September 30, 2009		December 31, 2009			March 31, 2010		June 30, 2010
	(in thousands)
Net income (loss)	$	10,833	$	16,331	$	(5,338	)	$	12,856		$	26,714	$	(97,181	)	$	9,893	$	(49,532	)
Depreciation and amortization	8,398		11,774		20,668			19,778			21,505		20,360			19,732		23,154
Interest expense	2,129		5,025		21,339			20,758			19,388		19,383			23,918		24,806
Income tax expense (recovery)	5,541		3,626		(790		)	(4,332		)	4,458		(11,985		)	2,804		(17,787		)
EBITDA	$	26,901	$	36,756	$	35,879		$	49,060		$	72,065	$	(69,423	)	$	56,347	$	(19,359	)

(1)For comparative purposes, results for the three months ended December 31, 2008 are combined to include the Predecessor and Successor periods. The combination is not a presentation in accordance with either Canadian GAAP or U.S. GAAP. However, we believe it is a useful presentation because it allows the financial data to be analyzed across comparable periods.

In addition, we present Pro Forma Adjusted EBITDA because it is used in calculating our covenant compliance under the indentures governing our long-term debt. EBITDA and Pro Forma Adjusted EBITDA as presented herein are not recognized measures under Canadian or U.S. 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 net income 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 June 30, 2009, debt extinguishment costs 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 Consolidated Interest Expense is less than two to one on a trailing four-quarter basis. Our Consolidated Interest Expense, excluding the accretion of debt issuance costs, for the twelve months ended June 30, 2010 was $77.8 million. For the twelve months ended June 30, 2010, our ratio of Pro Forma Adjusted EBITDA to Consolidated Interest Expense was 1.7:1. We believe that disclosing the Pro Forma Adjusted EBITDA and the ratio of Pro Forma Adjusted EBITDA to 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.

The following table reconciles EBITDA to Pro Forma Adjusted EBITDA for each of the last four quarters and for the twelve months ended June 30, 2010:

	Successor
	Three months ended												Twelve months ended
	September 30, 2009			December 31, 2009			March 31, 2010			June 30, 2010			June 30, 2010
	(in thousands)
EBITDA	$	72,065		$	(69,423	)	$	56,347		$	(19,359	)	$	39,630
Unrealized foreign exchange loss (gain) on long term debt(a)	(50,568		)	(19,405		)	(20,800		)	39,269			(51,504		)
Net unrealized loss (gain) from financial instruments(b)	(4,592		)	274			696			(1,986		)	(5,608		)
Employee stock option plan(c)	6,717			2,240			1,150			1,260			11,367
Recent acquisitions(d)	8,389			8,419			4,665			2,006			23,479
EBITDA adjustments relating to associates (e)	—			—			312			637			949
Management fee(f)	259			255			271			256			1,041
Impairment of goodwill and intangible assets(g)	—			114,115			—			—			114,115
Non-recurring payments(h)	—			500			—			—			500
Pro Forma Adjusted EBITDA	$	32,270		$	36,975		$	42,641		$	22,083		$	133,969

(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 derivatives 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 to manage foreign exchange risks, although we do not formally designate these derivatives as hedges for Canadian GAAP or U.S. GAAP accounting purposes. Accordingly, the unrealized gains or losses on these derivatives 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. If we formally designated the derivatives as effective hedges, unrealized gains and losses related to the derivatives would be deferred and would be recognized in the income statement when the hedged forecasted transaction affects earnings. The amount of this adjustment would differ in future periods based on the fluctuation in the fair value of outstanding derivatives at each balance sheet date.

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

(d)Reflects the pro forma effect of our acquisitions of Johnstone, Aarcam and Taylor on our Pro Forma Adjusted EBITDA as if the acquisitions took place on July 1, 2009. The pro forma impact of our Turner and Superior Propane business and asset acquisitions were not considered material. Prior periods have been adjusted as necessary to reflect the pro-forma impact of our acquisitions in those periods.

(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)In the fourth quarter of 2009, we recorded a non-cash impairment charge relating to goodwill and intangible assets of our truck transportation segment totalling $114.1 million.

(h)Represents professional fees incurred of $0.5 million relating to due diligence for an acquisition that was not consummated in 2009.

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 facilities for liquidity. We believe that we have sufficient liquidity at June 30, 2010 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 and we can give no assurance that funds will be available on acceptable terms.

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 and six months ended June 30, 2010 and 2009:

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	(in thousands)
Statement of Cash Flows
Cash flows provided by (used in):
Operating activities	$	(12,620	)	$	(17,618	)	$	8,077		$	(15,738	)
Investing activities	(166,702		)	(45,859		)	(196,424		)	(54,900		)
Financing activities	28,462			(16,221		)	198,075			(16,221		)

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 payments for the provision of contract trucking services, field operating expenses and general and administrative 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.

During the last 18 months, average crude oil values have generally risen and business activity levels have increased. As a result, additional working capital has been necessary for increased inventory levels and higher accounts receivable balances relative to trade accounts payable.

Cash used in operations in the three ended June 30, 2010 was $12.6 million and cash provided by operations in the six months ended June 30, 2010 was $8.1 million compared to $17.6 million and $15.7 million used in operations in the three and six months ended June 30, 2009 respectively. The decrease in cash used was primarily attributable to a decrease in cash used to fund working capital in the three and six months ended June 30, 2010 compared to the three and six months ended June 30, 2009, that was largely driven by a decrease in the amount of cash used to fund the change in inventory. Inventory increased by $0.9 million and $10.4 million in the three and six months ended June 30, 2010, respectively, compared to an increase in inventory of $22.8 million and $50.4 million in the three and six months ended June 30, 2009, respectively, offset against this was a decrease in cash from operations as a result of lower segment profits and an increase in interest expense in the current year periods.

Cash used in investing activities

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

Cash used in investing activities in the three and six months ended June 30, 2010 was $166.7 million and $196.4 million, respectively, compared to $45.9 million and $54.9 million in the three and six months ended June 30, 2009 respectively. The increase was primarily as a result of an increase in business acquisitions in the three and six months ended June 30, 2010 compared to the same periods in 2009. Total business acquisitions in the three and six months ended June 30, 2010 were $153.1 million and $177.8 million, respectively, compared to $6.9 million in both the three and six months ended June 30, 2009. In the six months ended June 30, 2010, we acquired 100% of the outstanding units of Taylor for $153.1 million, and 100% of the common shares of Johnstone for $21.3 million and Aarcam for $3.4 million. In the three and six months ended June 30, 2009, we acquired 100% of the outstanding common shares of Bridge Creek for $6.9 million.

Total capital expenditures in the six months ended June 30, 2010 and 2009 were $21.2 million and $13.3 million, respectively. See “—Executive Overview” for a summary of these capital expenditures.

Cash provided by (used in) financing activities

Cash provided by financing activities in the three months ended June 30, 2010 was $28.5 million compared to $16.2 million used in financing in the three months ended June 30, 2009. Cash provided by financing activities in the six months ended June 30, 2010 was $198.1 million, compared to $16.2 million used in financing in the six months ended June 30, 2009. The cash provided by financing in the six months ended June 30, 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 and a debt discount totalling $12.2 million. In the six months ended June 30, 2010, we also had drawn $99.5 million against our liquidity facility, that was offset by repayments of $95.8 million. In the three months ended June 30, 2010, the cash provided by financing activities related to $99.5 million drawn against our liquidity facility that was offset by repayments of $70.8 million.  The cash used in financing activities in the three and six months ended June 30, 2009 was as a result of the issuance of the 11.75% First Lien Senior Secured Notes (“First Lien Notes”) in the aggregate amount of U.S.$560.0 million, the proceeds of which were used to repay Bridge Loans of U.S.$545.0 million and to pay debt issue and discount costs of $32.9 million.

As of June 30, 2010, 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 an original term of five years expiring on May 27, 2014, and accrue interest at 11.75% per annum. The Senior Notes have an original 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 restricted subsidiaries. Additionally, we have a liquidity facility of up to U.S.$150.0 million, the proceeds of which are available to provide financing for working capital and other general corporate purposes. At June 30, 2010, we had $28.7 million drawn against this facility and we had issued letters of credit totalling $21.1 million. At June 30, 2010, the Company had restricted cash of $14.3 million.

The terms of our liquidity facility require us to comply with financial covenants when availability under the facility is less than 15%, including maintaining a fixed charge coverage ratio of at least 1.1 to 1.0. As of June 30, 2010, we had $28.7 million drawn and issued letters of credit of $21.1 million against the facility, and therefore the compliance with the financial ratio has not been applicable. If we fail to comply with the financial covenants, the lenders may declare an event of default under the liquidity 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 liquidity facility, and could result in an acceleration of amounts due and payable under the First Lien Notes and Senior Notes. As part of an amendment to the liquidity facility in October 2009, 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 First Lien Notes, the Senior Notes and the liquidity 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. The First Lien Notes, the Senior Notes and the liquidity 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 June 30, 2010, we were in compliance with all our non-financial covenants under our First Lien Notes, Senior Notes and liquidity facility.

Liquidity sources, requirements and contractual cash requirement and commitments

Our management believes that our cash on hand, together with cash from operations and borrowings under our credit facilities, will be adequate to meet our working capital, capital expenditures, debt service and other cash requirements for at least the next year. However, 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 $21.2 million and acquisitions, including equity investments amounted to $180.8 million during the six months ended June 30, 2010. In addition, on August 25, 2010, we completed the acquisition of the remaining equity interests in BRT for approximately $55.0 million. We have identified and approved additional capital projects (excluding acquisitions) that we expect to undertake over the next 12 to 18 months. While we anticipate that these anticipated 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.

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.

We or our affiliates may retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchase, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material and could have a material effect on the trading market for such debt and on our liquidity, cash flows and capital commitments and resources. Additionally, the indentures governing the First Lien Notes and Senior Notes limits 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 then-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 meet the coverage ratio.  As a result of the issuance of the Senior Notes, at June 30, 2010, we did not meet this ratio and we expect that we will not be able to meet this ratio at certain times throughout 2010.

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, Hunting has indemnified us for any increased income taxes as a result of these audits relating to periods prior to the date of the Acquisition.

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. Estimates of asset retirement obligation 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.

Contractual obligations

The following table presents, at June 30, 2010, 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)	$	806,056	$	—	$	—	$	593,936	$	212,120
Interest payments on long-term debt(1)	448,265		45,500		181,999		146,524		74,242
Operating lease obligations	125,211		9,083		34,921		22,972		58,235
Total contractual obligations	$	1,379,532	$	54,583	$	216,920	$	763,432	$	344,597

(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 June 30, 2010 of U.S.$0.9429 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 commodity trading risk management policy that has been approved by our Board of Directors. We also 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 LPG, and expected purchases and sales of these commodities (relating primarily to crude oil, roofing flux, propane sales and purchases of natural gasoline). The derivative instruments utilized consist primarily of futures and option contracts traded on the NYMEX, ICE and over-the-counter transactions, including swap and option contracts entered into with financial institutions and other energy companies. Our policy is to purchase 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 for short periods of time 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. This accounting treatment is discussed further in note 1 of our audited consolidated financial statements.

The fair value of futures contracts is based on quoted market prices obtained from the NYMEX or ICE. The fair value of swaps and option contracts is estimated based on quoted prices from various sources such as independent reporting services, industry 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 exist as at June 30, 2010 and December 31, 2009. 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 $2.2 million as of June 30, 2010, and by $7.9 million as of June 30, 2009. A 15% unfavorable change would decrease our net income by $2.2 million as of June 30, 2010, and by $8.3 million as of June 30, 2009. However, these changes may be offset by the use of one or more commonplace risk management strategies.

Interest rate risks.  Prior to the issuance of our First Lien Notes on May 27, 2009, we were subject to interest rate risk on our long-term debt in connection with the borrowings under our Bridge Loans. The amounts outstanding on our Bridge Loans were floating rate loans, which had exposure to changes in market interest rates. However, 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 liquidity facility, we are subject to interest rate risk, as borrowings 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. For the three and six months ended June 30, 2010, the impact on net income for a 100 basis point change in interest rates on the outstanding amount under our liquidity 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. 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 $1.2 million as of June 30, 2010 and by $1.0 million as of June 30, 2009. A corresponding favorable change would increase our net income by $1.2 million as of June 30, 2010 and by $1.0 million as of June 30, 2009. 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 June 30, 2010, 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 $34.7 million as of June 30, 2010, and by $27.8 million as of June 30, 2009. A corresponding favorable change would increase our net income by $34.7 million as of June 30, 2010, and by $27.8 million as of June 30, 2009. 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 June 30, 2010 would increase our annual interest expense by $4.6 million. A 5% favorable change in the value of the Canadian dollar relative to the U.S. dollar as of June 30, 2010 would decrease our annual interest expense by $4.6 million.