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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(Mark One)
o | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| |
OR |
| |
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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For the fiscal year ended December 31, 2010 |
OR |
|
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| |
OR |
| |
o | SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Date of Event Requiring This Shell Company Report
For the transition period from to
Commission File Number [333-164885]
GIBSON ENERGY ULC
(Exact Name of Registrant as Specified in Its Charter)
Not Applicable
(Translation of Registrant’s Name into English)
Alberta
(Jurisdiction of Incorporation or Organization)
1700, 440-2nd Ave S.W., Calgary, Alberta T2P 5E9, Canada
(Address of Principal Executive Offices)
T. Murray Carey,
Vice President, General Counsel and Secretary
Gibson Energy ULC
1700, 440-2nd Ave S.W.,
Calgary, Alberta T2P 5E9, Canada
Tel.: +1.403.206.4000
Fax: +1.403.206.4001
(Name, Telephone, E-mail and/or Facsimile Number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of Each Class | | Name of Each Exchange on Which Registered |
None | | None |
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
(Title of Class)
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
11.75% First Lien Senior Secured Notes due 2014
10.00% Senior Notes due 2018
(Title of Class)
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
| 537,656 Class A common shares |
| 100,000 preferred shares |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes x No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
o Yes x No
Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
x Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
o Yes o No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | | Accelerated filer o | | Non-accelerated filer x |
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
U.S. GAAP o | | International Financial Reporting Standards as issued
by the International Accounting Standards Board o | | Other x |
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
x Item 17 o Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
o Yes x No
(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.
o Yes o No
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EXPLANATORY NOTES
The Company
We are a North American company incorporated under the laws of the Province of Alberta, Canada. Our head office is located at 1700, 440-2nd Avenue, S.W., Calgary, Alberta, Canada T2P 5E9 and our telephone number is +1.403.206.4000. We maintain a website at www.gibsons.com. The information on our website is not a part of this Form 20-F.
On December 12, 2008, Gibson Acquisition ULC, an Alberta unlimited liability corporation (“Gibson AcquisitionCo”), an indirect wholly owned subsidiary of R/C Guitar Coöperatief 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.
Unless otherwise indicated or required by the context, as used in this Form 20-F, the terms “Gibson,” the “Company,” “we,” “our” and “us” refer to Gibson Energy Holding ULC and its subsidiaries that are consolidated under Canadian generally accepted accounting principles. The term “Issuers” refers to both Gibson Energy ULC and GEP Midstream Finance Corp. The term “Predecessor” refers to Gibson Energy Holdings Inc. for the periods prior to the Acquisition on December 12, 2008 and the term “Successor” refers to Gibson Energy Holding ULC for the period subsequent to the Acquisition on December 12, 2008.
The term “First Lien Notes” refers to our First Lien Senior Secured Notes issued on May 27, 2009 in an aggregate principal amount of U.S.$560.0 million. The term “Senior Notes” refers to our Unsecured Senior Notes issued on January 19, 2010 in an aggregate principal amount of U.S.$200.0 million. The term “Notes” refers to both the First Lien Notes and the Senior Notes. The term “Credit facility” refers to our asset backed credit facility of up to U.S.$200.0 million.
Presentation of Financial Information
Predecessor results for periods prior to the Acquisition on December 12, 2008 have been presented separately from Successor results subsequent to the Acquisition. To facilitate a discussion of certain results of operations across periods, we have combined certain Predecessor results with Successor results for the year ended December 31, 2008. The combined information does not comply with Canadian generally accepted accounting principles (“Canadian GAAP”) or accounting principles generally accepted in the United States of America (“U.S. GAAP”).
The consolidated financial statements included in this Form 20-F are presented in Canadian dollars and have been prepared in accordance with Canadian GAAP, which differs in certain respects from U.S. GAAP. For a discussion of the principal differences between Canadian GAAP and U.S. GAAP as they pertain to us, see note 25 to our audited consolidated financial statements. References to $ and “dollars” are to Canadian dollars and references to “U.S.$” and “U.S. dollars” are to United States dollars.
This Form 20-F includes certain financial measures that do not comply with Canadian GAAP or U.S. GAAP, such as EBITDA and Pro Forma Adjusted EBITDA. As used in this Form 20-F, EBITDA represents consolidated net income (loss) before deduction of amounts for interest expense, income taxes, depreciation and amortization. Pro Forma Adjusted EBITDA is presented because it is used in calculating our covenant compliance under the indentures governing the Notes. Pro Forma Adjusted EBITDA differs from the term “EBITDA” as it is commonly used. Pro Forma Adjusted EBITDA is defined as consolidated net income (loss) before interest expense, income taxes, depreciation, amortization, accretion expense, other non-cash expenses and charges deducted in determining consolidated net income (loss), including movement in the unrealized gains and losses on 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 certain acquisitions that took place subsequent to December 31, 2009 and other adjustments that are considered non-recurring in nature. EBITDA and Pro Forma Adjusted EBITDA are not measures of operating performance or liquidity under
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Canadian GAAP or U.S. GAAP. EBITDA, as used in this Form 20-F, is not necessarily comparable with similarly titled measures used by other companies. Management believes that EBITDA may be useful in assessing our operating performance and as an indicator of our ability to service or incur indebtedness, make capital expenditures and finance working capital requirements. Pro Forma Adjusted EBITDA may not be comparable to such calculations used in debt covenants applicable to other companies. Refer to Item 5. “Operating and Financial Review and Prospects — Management’s Discussion and Analysis of Financial Condition and Results of Operation — Summary of Quarterly Results” for a reconciliation of consolidated net income (loss) to EBITDA and Pro Forma Adjusted EBITDA. The items excluded in determining EBITDA are significant in assessing our operating results and liquidity. Therefore, EBITDA should not be considered in isolation or as an alternative to cash from operating activities or other income or cash flow data prepared in accordance with Canadian GAAP or U.S. GAAP.
Market and Industry Data
Market data and other statistical information used throughout this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including the Energy Information Administration of the U.S. Department of Energy, the National Energy Board, Standard & Poor’s, the Canadian Association of Petroleum Producers and the Oil and Gas Journal. Some data is also based on our good faith estimates, which are derived from our review of internal data and information, as well as the independent sources listed above. Although we believe these sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.
DISCLOSURE REGARDING FORWARD-LOOKING INFORMATION
This Form 20-F contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). You can generally identify forward-looking statements by our use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “seek,” “should,” or “will” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about (1) general market conditions, competition and pricing; and (2) our expectations, beliefs, plans, strategies, objectives, prospects, assumptions or future events or performance contained in this Form 20-F are forward-looking statements.
We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors, including those discussed in this Form 20-F under the headings Item 3.D. “Risk Factors,” Item 5. “Operating and Financial Review and Prospects” and Item 4B. “Business Overview,” may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the factors that could cause actual results to differ materially from those expressed or implied by the forward-looking statements include:
Risks Relating to Our Business
· our financial results depend on the demand for the petroleum products that we transport, store, sell, process and distribute;
· we may not successfully balance our purchases and sales of crude oil, condensate, propane, NGL’s and natural gas, which would increase our exposure to commodity price risks;
· we are exposed to foreign exchange risk due to some of our sales and indebtedness being denominated in U.S. dollars, which may have a negative impact on our results of operations;
· some of our business segments are dependent on certain major customers, and a loss of one or more major customers could have a material adverse effect on segment profitability;
· our marketing activities expose us to price and market risks which could adversely impact our financial condition;
· we face intense competition in all areas of our business and may not be able to successfully compete with our competitors, which could lead to lower levels of profits and reduce the amount of cash we generate;
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· we may not be able to fully implement or capitalize upon planned growth projects and may not be successful in making acquisitions;
· our success depends on our ability to retain the current members of our senior management team and other key personnel;
· if our reputation deteriorates, it could have negative impacts on us including revenue loss and reduction in customer base;
· our access to credit from our suppliers could be restricted;
· the seasonal nature of certain of our business activities and adverse weather conditions may adversely impact our revenues and results of operations;
· potential future acquisitions or investments in other companies may have a negative impact on our business;
· our growth strategy may require access to new capital. Tightened capital markets or other factors that increase our cost of capital could impair our ability to grow;
· we are dependent on access to parts and equipment from certain key suppliers and we may be adversely affected if we are unable to maintain those relationships;
· a material decrease in the production of crude oil from the oil fields served by our pipelines could materially reduce our revenues;
· our business involves many hazards and operational risks which could adversely impact our operations and cause us to incur substantial liabilities;
· our terminal and pipeline systems are dependent upon their interconnections with terminals and pipelines owned and operated by others;
· a material decrease in our throughput levels, which are dependent on transportation contracts or tolling arrangements with third parties, could adversely affect our business;
· we are responsible for the decommissioning, abandonment and reclamation costs for our facilities and these costs may be substantial;
· our business may be affected by legislative and regulatory changes which could have a negative impact on us;
· we are subject to numerous environmental and health and safety regulations that have become more stringent in recent years and may result in increased liabilities and increased capital expenditures by us;
· our revenues from third-party customers are generated under contracts that must be renegotiated periodically and that allow the customer to reduce or suspend performance in some circumstances, which could cause our revenues from those contracts to decline;
· we may not have or be able to obtain adequate insurance to cover all risks incident to our business;
· some of our employees are unionized and any work stoppages or unexpected increases in salary, wages and benefits could have an adverse effect on our financial results;
· our operations are dependent on technology and a breakdown of that technology could adversely impact the accuracy of our revenues and results of operations;
· some of our storage tanks and portions of our pipeline system have been in service for several decades, and our operating and maintenance capital costs could increase due to aging equipment;
· our propane and NGL marketing and distribution segment depends on construction sector activity levels, which tend to be cyclical and which differ throughout the regions in which we operate;
· higher fuel prices could materially affect our results of operations and financial condition;
· some of our planned facilities are jointly owned by third parties and it may not be possible for us to obtain approval from those third parties for expansion projects which may adversely affect our ability to expand in the future;
· our operations may incur substantial costs to comply with future climate control legislation and regulatory initiatives;
· certain private equity investment funds affiliated with Riverstone own 100% of our common shares and their interests may not be aligned with yours;
· if we fail to maintain proper and effective internal controls, our ability to produce accurate financial statements could be impaired, which could adversely affect our operating results, our ability to operate our business and investors’ views of us;
· we have adopted new accounting standards in 2011, and this adoption may have a material impact on our financial statements; and
· litigation risk.
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Risks Relating to the Notes
· our substantial indebtedness could adversely affect our financial health, restrict our activities and affect our ability to meet our obligations under the Notes;
· the right to receive payments on the Senior Notes is effectively subordinated to the rights of our existing and future secured creditors. Further, the guarantees of the Senior Notes are effectively subordinated to all our guarantors’ existing and future secured indebtedness to the extent of the value of the assets securing such indebtedness;
· our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities;
· the First Lien Notes are not secured by certain excluded property and assets;
· any future pledges of collateral may be avoidable;
· the collateral is subject to casualty risks;
· the collateral agent’s ability to exercise remedies is limited;
· rights of holders of the First Lien Notes in the collateral may be adversely affected by the failure to perfect security interests in certain collateral or the perfection of liens on the collateral by other creditors;
· fixed charge mortgages are registered against only five of our owned real properties for which title insurance policies were obtained. Other than such five properties, there can be no assurance therefore that the mortgages securing the First Lien Notes are encumbering the correct real properties and that there are no liens other than those permitted by the indenture governing the First Lien Notes encumbering our owned real properties;
· despite current indebtedness levels, we and our subsidiaries may still be able to incur substantially more debt, including additional secured indebtedness. This could further exacerbate the risks associated with our substantial financial leverage;
· to service our indebtedness, we will require a significant amount of cash and our ability to generate cash depends on many factors beyond our control;
· we may not have the ability to raise funds necessary to finance any change of control offer required under the indentures;
· canadian insolvency laws may adversely affect a recovery by holders of the Notes;
· because several of our directors and officers reside in Canada, the holders of the Notes may not be able to effect service of process upon them or enforce civil liabilities against them under the U.S. federal securities laws;
· if there is a foreclosure on the collateral securing the First Lien Notes, you may be subject to claims and liabilities under environmental laws and regulations; and
· federal, state and provincial laws allow courts, under certain circumstances, to void guarantees and require Note holders to return payments received from guarantors.
Given these risks and uncertainties, you are cautioned not to place undue reliance on such forward-looking statements. The forward-looking statements included in this Form 20-F are made only as of the date hereof. Readers are cautioned that the foregoing list of risk factors is not exhaustive and that the forward-looking statements contained in this Form 20-F are expressly qualified by this cautionary statement. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of such statements to reflect future events or developments.
PART I
Item 1. Identity of Directors, Senior Management and Advisors
Not Applicable
Item 2. Offer Statistics and Expected Timetable
Not Applicable
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Item 3. Key Information
3.A. SELECTED FINANCIAL INFORMATION
The selected historical consolidated financial data as of December 31, 2010 and 2009 and for the year ended December 31, 2010, the year ended December 31, 2009, the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008 have been derived from our audited consolidated financial statements included elsewhere in this Form 20-F. These consolidated financial statements were prepared in accordance with Canadian GAAP, which differs in some material respects from U.S. GAAP. For a discussion of the principal differences between Canadian GAAP and U.S. GAAP applicable to the Company see Note 25 to our audited consolidated financial statements included elsewhere in this Form 20-F. This information, in our opinion, reflects all adjustments necessary for a fair statement of our operating results and financial condition for such periods and as of such dates. You should read the selected historical consolidated financial information together with Item 3.D. “Risk Factors,” Item 5. “Operating and Financial Review and Prospects” and our historical consolidated financial statements, including the related notes included elsewhere in this Form 20-F.
| | Successor | | Predecessor | |
| | Year ended
December 31, | | Period from
December 13,
to
December 31, | | Period from
January 1,
to
December 12, | | Year ended
December 31, | |
| | 2010 | | 2009 | | 2008 | | 2008 | | 2007 | | 2006 | |
| | (in thousands) | |
Statement of Income Data | | | | | | | | | | | | | |
Revenues | | $ | 3,677,988 | | $ | 3,454,137 | | $ | 135,471 | | $ | 4,648,665 | | $ | 3,332,486 | | $ | 2,988,500 | |
Cost of sales, excluding depreciation and amortization | | 3,506,559 | | 3,292,421 | | 124,972 | | 4,491,139 | | 3,180,020 | | 2,833,695 | |
Depreciation and amortization | | 94,145 | | 82,311 | | 4,881 | | 31,506 | | 27,845 | | 26,000 | |
General and administrative expenses | | 24,935 | | 24,731 | | 615 | | 31,365 | | 22,374 | | 21,631 | |
Stock based compensation | | 4,629 | | 8,957 | | — | | — | | — | | — | |
Impairment of goodwill and intangible assets | | — | | 114,115 | | — | | — | | — | | — | |
Accretion expense | | 787 | | 785 | | 22 | | 404 | | 391 | | 364 | |
Debt extinguishment costs | | — | | 18,517 | | — | | — | | — | | — | |
Foreign exchange and other income | | (39,327 | ) | (92,970 | ) | (4,460 | ) | (601 | ) | (2,572 | ) | (69 | ) |
Interest expense | | 99,451 | | 80,868 | | 3,431 | | 8,335 | | 8,266 | | 7,545 | |
Income (loss) before income taxes | | (13,191 | ) | (75,598 | ) | 6,010 | | 86,517 | | 96,162 | | 99,334 | |
Income tax expense (recovery) | | (13,346 | ) | (12,649 | ) | 1,030 | | 25,199 | | 20,198 | | 31,149 | |
Net income (loss) | | $ | 155 | | $ | (62,949 | ) | $ | 4,980 | | $ | 61,318 | | $ | 75,964 | | $ | 68,185 | |
| | | | | | | | | | | | | |
U.S. GAAP Data: | | | | | | | | | | | | | |
Net income (loss) under U.S. GAAP | | $ | (953 | ) | $ | (62,859 | ) | $ | 4,980 | | $ | 61,358 | | $ | 75,654 | | | |
Statement of Cash Flows Data: | | | | | | | | | | | | | |
Cash flows provided by (used in): | | | | | | | | | | | | | |
Operating activities | | $ | 51,660 | | $ | 2,070 | | $ | 36,837 | | $ | 74,048 | | $ | 78,085 | | $ | 101,847 | |
Investing activities | | (281,735 | ) | (95,203 | ) | (951,590 | ) | (74,536 | ) | (99,159 | ) | (47,890 | ) |
Financing activities | | 212,844 | | 6,444 | | 1,027,705 | | (7,548 | ) | 30,059 | | (40,620 | ) |
Other Financial Data | | | | | | | | | | | | | |
Capital expenditures | | | | | | | | | | | | | |
Acquisitions, net of cash acquired (1) | | $ | 232,746 | | $ | 15,165 | | $ | — | | $ | 14,430 | | $ | 46,458 | | $ | 1,800 | |
Property, plant and equipment | | 61,682 | | 36,967 | | 2,982 | | 43,672 | | 60,521 | | 42,213 | |
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| | Successor | | Predecessor | |
| | As of December 31, | |
| | 2010 | | 2009 | | 2008 | | 2007 | | 2006 | |
| | (in thousands) | |
Balance Sheet Data: | | | | | | | | | | | |
Cash and cash equivalents | | $ | 7,225 | | $ | 26,263 | | $ | 112,952 | | $ | 25,061 | | $ | 16,076 | |
Property, plant and equipment, net | | 652,885 | | 598,826 | | 603,980 | | 295,545 | | 244,646 | |
Total assets | | 2,022,765 | | 1,673,894 | | 1,849,700 | | 849,963 | | 692,621 | |
Long-term debt | | 718,154 | | 553,942 | | 640,082 | | — | | — | |
Amounts due to affiliates | | — | | — | | — | | 164,500 | | 106,500 | |
Shareholder’s equity | | 586,661 | | 588,644 | | 642,636 | | 258,170 | | 209,493 | |
U.S. GAAP Data: | | | | | | | | | | | |
Total assets | | $ | 2,059,094 | | $ | 1,706,175 | | $ | 1,877,025 | | $ | 857,286 | | | |
Liabilities | | 1,475,226 | | 1,118,870 | | 1,234,389 | | 599,091 | | | |
Preferred shares (2) | | 127,068 | | 113,034 | | 100,625 | | — | | | |
Shareholder’s equity | | 456,800 | | 474,271 | | 542,011 | | 258,195 | | | |
| | | | | | | | | | | | | | | | |
(1) Does not include amounts relating to the Acquisition or our equity investments in Battle River Terminal ULC and Palko Environmental Ltd.
(2) Contingently redeemable convertible preferred shares represent temporary equity (mezzanine) under U.S. GAAP.
CURRENCY PRESENTATION AND EXCHANGE RATE INFORMATION
The following chart shows, for the period from January 1, 2006 through December 31, 2010, the period end, average, high and low noon buying rates in the City of New York for cable transfers of Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York expressed as U.S. dollars per $1.00.
| | U.S dollars per $1.00 | |
Period | | High | | Low | | Period
average | | Period
end | |
2006 | | 0.9100 | | 0.8528 | | 0.8847 | | 0.8582 | |
2007 | | 1.0908 | | 0.8374 | | 0.9419 | | 1.0120 | |
2008 | | 1.0162 | | 0.7727 | | 0.9399 | | 0.8170 | |
2009 | | 0.9719 | | 0.7695 | | 0.8834 | | 0.9559 | |
2010 | | 1.0040 | | 0.9280 | | 0.9714 | | 0.9991 | |
September | | 0.9786 | | 0.9506 | | 0.9681 | | 0.9712 | |
October | | 0.9972 | | 0.9689 | | 0.9818 | | 0.9805 | |
November | | 0.9999 | | 0.9741 | | 0.9871 | | 0.9741 | |
December | | 0.9996 | | 0.9827 | | 0.9920 | | 0.9991 | |
2011 | | | | | | | | | |
January | | 1.0138 | | 0.9980 | | 1.0061 | | 0.9980 | |
February | | 1.0270 | | 1.0045 | | 1.0125 | | 1.0270 | |
March | | 1.0324 | | 1.0080 | | 1.0240 | | 1.0291 | |
April (April 1 through April 22) | | 1.0506 | | 1.0321 | | 1.0419 | | 1.0488 | |
3.B. CAPITALIZATION AND INDEBTEDNESS
Not Applicable
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3.D. Risk Factors
This Form 20-F also contains forward-looking statements that involve risks and uncertainties and the cautionary statement regarding the forward-looking statements set forth under the caption “Disclosure Regarding Forward-Looking Information.” Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks described below and elsewhere in this Form 20-F.
Risks Relating to Our Business
Our financial results depend on the demand for the petroleum products that we transport, store, sell, process and distribute.
Any sustained decrease in demand for crude oil and petroleum products in the markets we serve could result in a significant reduction in the volume of products that we transport in our pipelines, store at our terminals and distribute through our trucking business, and thereby significantly reduce our cash flow and revenues. Factors that could lead to a decrease in market demand include:
· lower demand by consumers for refined products, including asphalt and wellsite fluids, as a result of recession or other adverse economic conditions or due to high prices caused by an increase in the market price of crude oil, which is subject to wide fluctuations in response to changes in global and regional supply over which we have no control, or higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline or other refined products and result in lower spending by consumers and businesses on transportation fuels such as gasoline, aviation fuel and diesel;
· an increase in fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles, technological advances by manufacturers, governmental or regulatory actions or otherwise;
· provincial, state and federal legislation either already in place or under development requiring the inclusion of ethanol and use of biodiesel which may negatively affect the overall demand for crude oil products;
· lower demand by the oil and gas drilling industry for products such as drilling mud activities and for fluids as a result of legislation regulating hydraulic fractioning currently being considered by the U.S. Congress and a number of U.S. states and the Province of Quebec;
· technological advances in the production and longevity of fuel cells and solar, electric and battery-powered engines; and
· fluctuations in demand for crude oil, such as those caused by refinery downtime or shutdowns, could also significantly reduce market demand and, therefore, reduce our revenues.
We cannot predict and we do not have control over the impact of future economic and political conditions on the energy and petrochemical industries, which in turn could affect the demand for crude oil and petroleum products. As a result of decreased demand, we may experience a decrease in our margins and profitability.
We may not successfully balance our purchases and sales of crude oil, condensate, propane, NGL’s and natural gas, which would increase our exposure to commodity price risks.
We purchase from producers and other customers a substantial amount of crude oil, condensate, propane, NGL’s and natural gas for resale to third parties, including other marketers and end-users. We may not be successful in balancing our purchases and sales. A producer or supplier could fail to deliver contracted volumes or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause our purchases and sales to be
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unbalanced. While we attempt to balance our purchases and sales, if our purchases and sales are unbalanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating income and cash flows.
We are exposed to foreign exchange risk due to some of our sales and indebtedness being denominated in U.S. dollars, which may have a negative impact on our results of operations.
Our results are affected by the exchange rate between the Canadian and U.S. dollar. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease the Canadian dollar equivalent of revenues we receive from our U.S. activities and U.S. dollar denominated activities. Correspondingly, a decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the Canadian dollar equivalent of revenues received from our U.S. activities and U.S. dollar denominated activities. For the year ended December 31, 2010, approximately 20% of our revenue was from sales to customers in the United States. In addition, a change in the value of the Canadian dollar against the U.S. dollar will result in an increase or decrease in our U.S. dollar-denominated debt, as expressed in Canadian dollars, as well as in the related interest expense. While a portion of our sales generate cash denominated in U.S. dollars, to the extent that such U.S. dollar-denominated cash is less than the amounts required to service our U.S. dollar-denominated debt and pay other U.S. dollar-denominated expenses, we are exposed to currency fluctuations and exchange rate risks that may adversely affect our results of operations. For example, in 2010, the high and low noon buying rate for the Canadian dollar to U.S. dollar ranged between $1.0054:1 and $0.9278:1. Exchange rate fluctuations are beyond our control and there can be no guarantee that such fluctuations will not have a material adverse effect on our results of operations and cash flow available to service our obligations. Our practice is to selectively hedge our exposure to foreign currencies related to our ongoing operations, including to the U.S. dollar, through the use of futures and options contracts. However, there can be no guarantee that we will be able to fully mitigate our exposure to foreign exchange risk. We have not entered into hedging arrangements with respect to the principal of our U.S. dollar-denominated debt.
Some of our business segments are dependent on certain major customers, and a loss of one or more major customers could have a material adverse effect on segment profitability.
There can be no assurance that our current customers will continue their relationships with us or that we have adequately assessed their creditworthiness or that there will not be an unanticipated deterioration in their creditworthiness. The loss of one or more major customers or any material nonpayment or nonperformance by such customer, or any significant decrease in transportation services or any of our other services provided to a customer, prices paid, or any other changes to the terms of service with customers, could have a material adverse effect on our profitability.
Our marketing activities expose us to price and market risks which could adversely impact our financial condition.
We enter into contracts to purchase and sell crude oil, NGLs and natural gas. Most of these contracts are priced at floating market prices. These activities expose us to market risks resulting from movements in commodity prices between the time volumes are purchased and the time they are sold, from fluctuations in the margins between purchase prices and sales prices and, in some cases, may also expose us to currency exchange risk. The prices of the products that we market are subject to fluctuations as a result of such factors as seasonal demand changes, changes in crude oil and natural gas markets, and other factors. In many circumstances, purchase and sale contracts are not perfectly matched, as they are entered into at different times and for different values. Furthermore, we normally have a long position in most of the propane, NGL products and crude oil that we market, and may store propane and NGLs in order to meet seasonal demand and take advantage of seasonal pricing differentials, thereby resulting in inventory risk.
Because crude oil margins are earned by capturing spreads between different qualities of crude oil, our crude oil midstream business is subject to volatility in price differentials between crude oil streams and blending agents. In periods where such price differentials are wide, our opportunity to profit by capturing spreads is enhanced, and in periods where such price differentials are tighter, as has been the case in more recent periods, our opportunity to profit is reduced. As a result, in our propane, NGL and crude oil marketing businesses, margins, profitability and contributions to our Pro-Forma Adjusted EBITDA can vary significantly from period to period and volatility in the markets for these products may cause volatility in our financial results from period to period.
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To some extent, we can lessen certain elements of risk exposure through the integration of our marketing business with our facilities businesses. In spite of this integration, we remain exposed to market and commodity price risk. We manage this commodity risk in a number of ways, including the use of financial contracts and by offsetting some physical and financial contracts in terms of volumes, timing of performance and delivery obligations.
For example, in the context of NGL marketing, because NGL product prices are related to the price of crude oil, crude oil financial contracts are one of the more common price risk management strategies that we use. Also, in the context of crude oil marketing, we manage our exposure using West Texas Intermediate (“WTI”) based futures, options and swaps. These strategies are subject to basis risk between the prices of crude oil streams, WTI and NGL product values and therefore cannot be expected to fully offset future price movements. Furthermore, there is no guarantee that these strategies and other efforts to manage the marketing and inventory risks will generate profits or mitigate all the market and inventory risk associated with these activities. If we utilize price risk management strategies, we may forego the benefits that may otherwise be experienced if commodity prices were to increase. In addition, any non-compliance with our trading policies could result in significantly adverse financial effects. To the extent that we engage in these kinds of activities, we are also subject to credit risks associated with counterparties with whom we have contracts.
We face intense competition in all areas of our business and may not be able to successfully compete with our competitors, which could lead to lower levels of profits and reduce the amount of cash we generate.
We are subject to competition from other pipelines and terminals in the same markets as our assets, as well as from other means of transporting, storing and distributing petroleum products, including from other pipeline systems, terminal operators and integrated refining and marketing companies that own their own terminal facilities and that may be able to supply our customers with the same or comparable services on a more competitive basis. Our customers demand delivery of products on tight time schedules and in a number of geographic markets. If our quality of service declines or we cannot meet the demands of our customers, they may utilize the services of our competitors.
Our competitors include major integrated oil and gas companies and numerous other independent oil and gas companies, individual producers and operators and other terminal and pipeline operators. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers. Some of these competitors are substantially larger than us, have greater financial resources, and control substantially greater storage capacity than we do.
Our ability to compete could be harmed by numerous factors, including:
�� price competition;
· different cost structure;
· the perception that another company can provide better service;
· the availability of alternative supply points, or supply points located closer to the operations of our customers; and
· competition from other sources of energy.
Competitive forces may result in shortages of development opportunities for infrastructure to produce and transport production. It may also result in an oversupply of crude oil, natural gas, petroleum products and chemicals. Each of these factors could have a negative impact on costs and prices and, therefore, our financial results. If we are unable to compete with services offered by other midstream enterprises, our cash flow and revenues may be adversely affected.
We may not be able to fully implement or capitalize upon planned growth projects and may not be successful in making acquisitions.
We have a number of organic growth projects that require the expenditure of significant amounts of capital. Many of these projects involve numerous regulatory, environmental, commercial, weather-related, political and legal uncertainties that will be beyond our control. As these projects are undertaken, required approvals may not be obtained, may be delayed or may be
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obtained with conditions that materially alter the expected return associated with the underlying projects. Moreover, we will incur financing costs during the planning and construction phases of our growth projects. However, the operating cash flows we expect these projects to generate will not materialize until after the projects are completed. These projects may be completed behind schedule or in excess of budgeted cost. For example, we must compete with other companies for the materials and construction services required to complete these projects, and competition for these materials or services could result in significant delays and/or cost overruns. Any such cost overruns or unanticipated delays in the completion or commercial development of these projects could reduce our liquidity. We may construct facilities or other assets in anticipation of market demand that dissipates or market growth that never materializes. As a result of these uncertainties, the anticipated benefits associated with our capital projects may not be achieved.
Our success depends on our ability to retain the current members of our senior management team and other key personnel.
Our success depends to a significant extent on the continued services of our core senior management team and other key personnel. If one or more of these individuals were unable or unwilling to continue in their present positions, our business could be disrupted and we might not be able to find replacements on a timely basis or with the same level of skill and experience. Finding and hiring any such replacements could be costly and might require us to grant significant equity awards or other incentive compensation, which could adversely impact our financial results. We do not maintain key-person life insurance for any of our management personnel or other key employees. Furthermore, the ability to execute our business plan and expand our services will be dependent upon our ability to attract and retain qualified employees, which is constrained in times of strong industry activity. The failure to attract and retain a sufficient number of qualified drivers, owner-operators and lease operators for our truck transportation business could also have a material adverse effect on our profitability.
If our reputation deteriorates, it could have negative impacts on us including revenue loss and reduction in customer base.
Reputational risk is the potential for negative impacts that could result from the deterioration of our reputation with key customers. The potential for harming our corporate reputation exists in every business decision and all risks can have an impact on reputation, which in turn can negatively impact our business. Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, liquidity and regulatory and legal risks must all be managed effectively to safeguard our reputation. Negative impacts from a compromised reputation could include revenue loss and reduction in customer base.
Our access to credit from our suppliers could be restricted.
Our significant debt levels could restrict our ability to access credit from our suppliers, who may require increased performance assurances. If we are unable to access credit from our suppliers, our ability to purchase inventory could be decreased and our financial condition and results of operations could be negatively impacted.
The seasonal nature of certain of our business activities and adverse weather conditions may adversely impact our revenues and results of operations.
Certain of our segments are impacted by seasonality. Generally, our results are impacted in the second quarter due to road bans and other restrictions that impact overall activity levels in the Western Canada Sedimentary Basin (“WCSB”), and therefore negatively impact our trucking and wellsite fluids business in Canada. Certain oil and gas producing areas are only accessible in the winter months because the ground surrounding the drilling sites in these areas consists of swampy terrain. Harsh Canadian weather conditions are particularly challenging and can impede the movement of goods and increase the operating costs for the materials that can be transported, which can have a material adverse effect on our profitability.
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.
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Our propane and NGL marketing and distribution segment is characterized by a high degree of seasonality with much of the seasonality driven by the impact of weather on the need for heating and the amount of propane required to produce power for oil and gas related applications. Therefore, volumes are low during the summer months relative to the winter months. Operating profits are also considerably lower during the summer months. Approximately 68% of our revenues for the year ended December 31, 2010 attributable to propane were generated in the October-March winter heating season. A warm winter could therefore lead to reduced demand for propane which would negatively impact the cash flows of our propane and NGL marketing and distribution segment and could reduce our revenues.
Potential future acquisitions or investments in other companies may have a negative impact on our business.
We have historically expanded our truck transportation and propane and NGL marketing and distribution businesses through acquisitions and may seek to expand these or our other businesses through acquisitions. Our ability to grow our sales volumes is at least in part dependent upon our ability to complete acquisitions, to integrate those acquisitions into our operations, and upon the success of our marketing efforts to acquire new customers. We intend to consider and evaluate opportunities for growth acquisitions; however, there can be no assurance that we will find attractive acquisition candidates in the future, or that we will be able to acquire such candidates on economically acceptable terms. Acquisitions may require substantial capital and negotiations of potential acquisitions and the integration of acquired business operations could disrupt our business by diverting management away from day-to-day operations. The difficulties of integration may be increased by the necessity of coordinating geographically diverse organizations, integrating personnel with disparate business backgrounds and combining different corporate cultures. At times, acquisition candidates may have liabilities or adverse operating issues that we fail to discover through due diligence prior to the acquisition. If we consummate any future acquisitions, our capitalization and results of operations may change significantly.
Any acquisition involves potential risks, including, among other things:
· mistaken assumptions about volumes, revenues and costs, including synergies;
· an inability to successfully integrate the businesses we acquire;
· an inability to hire, train or retain qualified personnel to manage and operate our business and assets;
· the assumption of unknown liabilities;
· limitations on rights to indemnity from the seller;
· mistaken assumptions about the overall costs of equity or debt;
· the diversion of management’s and employees’ attention from other business concerns;
· unforeseen difficulties operating in new product areas or new geographic areas; and
· customer or key employee losses at the acquired businesses.
Acquisitions or investments may require us to expend significant amounts of cash, resulting in our inability to use these funds for other business purposes. The potential impairment or complete write-off of goodwill and other intangible assets related to any such acquisition may reduce our overall earnings, which in turn could negatively affect our capitalization and results of operations.
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Our growth strategy may require access to new capital. Tightened capital markets or other factors that increase our cost of capital could impair our ability to grow.
Any material acquisition or internal growth project will require access to capital. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. Our ability to maintain our targeted credit profile, including maintaining our credit ratings, could affect our cost of capital as well as our ability to execute our growth strategy.
We are dependent on access to parts and equipment from certain key suppliers and we may be adversely affected if we are unable to maintain those relationships.
Our ability to compete and expand will be dependent on having access, at a reasonable cost, to equipment, parts and components which are at least technologically equivalent to those utilized by our competitors, and to the development and acquisition of new and competitive technologies. Although we have individual distribution agreements with various key suppliers, there can be no assurance that those sources of equipment, parts or components or relationships with key suppliers will be maintained. If these sources are not maintained, our ability to compete may be impaired. We are able to access certain distributors and secure discounts on parts and components that would not be available if it were not for our relationship with certain key suppliers. Should the relationships with these key suppliers cease, the availability and cost of securing certain equipment and parts may be adversely affected.
A material decrease in the production of crude oil from the oil fields served by our pipelines could materially reduce our revenues.
Our conventional pipeline tariff revenues are based upon a variety of tolling arrangements, including “take-or-pay” contracts, cost of service arrangements and market-based tolls. As a result, certain pipeline tariff revenues are heavily dependent upon throughput levels of crude oil and condensate. The throughput on our crude oil pipelines depends on the availability of crude oil produced from the oil fields served by such pipelines, or through connections with pipelines owned by third parties. Crude oil production may decline for a number of reasons, including natural declines due to depleting wells, a material decrease in the price of crude oil, or the inability of producers to obtain necessary drilling or other permits from applicable governmental authorities. If we are unable to replace volumes lost due to a temporary or permanent material decrease in production or a decrease in demand from the oil fields served by our crude oil pipelines, our throughput could decline, reducing our revenue and cash flow. Certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes gathered or transported by our operations. As a result, we may experience declines in our margins and profitability if our volumes decrease.
Our business involves many hazards and operational risks which could adversely impact our operations and cause us to incur substantial liabilities.
Our operations are subject to the many hazards inherent in the transportation, storage and distribution of crude oil, natural gas and petroleum products, including:
· explosions, fires and accidents, including road and highway accidents involving our tanker trucks;
· damage to our tanker trucks, pipelines, storage tanks, terminals and related equipment;
· ruptures, leaks or releases of crude oil or petroleum products into the environment; and
· acts of terrorism or vandalism.
If any of these events were to occur, we could suffer substantial losses because of personal injury or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage resulting in curtailment
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or suspension of our related operations. Mechanical malfunctions, faulty measurement or other errors may also result in significant costs or lost revenues.
Our terminal and pipeline systems are dependent upon their interconnections with terminals and pipelines owned and operated by others.
Our terminal and pipeline systems are dependent upon their interconnections with other terminals and pipelines owned and operated by third parties to reach end markets and as a significant source of supply for our facilities. Outages at these terminals or reduced or interrupted throughput on these pipelines because of weather-related or other natural causes, testing, line repair, damage, reduced operating pressures or other causes could result in our being unable to deliver products to our customers from our terminals or receive products for storage at our terminals for processing at our refinery in Moose Jaw, or reduce shipments on our pipelines and could adversely affect our cash flows and revenues.
A material decrease in our throughput levels, which are dependent on transportation contracts or tolling arrangements with third parties, could adversely affect our business.
Throughput in certain of our terminals is or will be governed by transportation contracts or tolling arrangements with various producers of petroleum products. Any default by counterparties under such contracts or the expiration of any such contracts or tolling arrangements without renewal or replacement may have an adverse effect on our business, results of operations and financial condition.
We are responsible for the decommissioning, abandonment and reclamation costs for our facilities and these costs may be substantial.
We will be responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to us to execute our business plan and service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.
Our business may be affected by legislative and regulatory changes which could have a negative impact on us.
Our industry is highly regulated. There can be no guarantee that laws and other government programs relating to the oil and gas industry, the energy services industry and the transportation industry will not be changed in a manner which directly and adversely affects our business and there can be no assurance that the laws, regulations or rules governing our customers will not be changed in a manner which adversely affects our customers and, therefore, our business. For example, the “New Royalty Framework” introduced by the Alberta Government took effect on January 1, 2009, and modified the manner in which royalties will be charged on oil and gas producing properties in Alberta.
Increased royalty rates could adversely affect drilling activity in Alberta in future years. While the applicable royalty rate does not directly impact us as we have no producing properties, these rate increases may indirectly impact our results should the producers and shippers operating in areas serviced by us decide to take actions, such as reduced capital programs or curtailment of volumes shipped, as a result of the increased royalty rates.
In addition, our pipelines and facilities are potentially subject to common carrier and common processor applications and to rate setting by regulatory authorities in the event agreement on fees or tariffs cannot be reached with producers. To the extent that producers believe processing fees or tariffs with respect to pipelines and facilities are too high, they may seek rate relief through regulatory means. If regulations were passed lowering or capping our rates and tariffs, our results of operations and cash flows could be adversely affected.
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Petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, provincial, state and local agencies have the authority to prescribe specific product quality specifications for commodities sold into the public market. Changes in product quality specifications or blending requirements could reduce our throughput volume, require us to incur additional handling costs or require capital expenditures. For instance, different product specifications for different markets impact the fungibility of the products in our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenues, our cash flows could be adversely affected. In addition, changes in the product quality of the products we receive on our petroleum products pipeline system could reduce or eliminate our ability to blend products.
Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and U.S. customs and tax issues and toxic substance certifications. Such regulations include the Short Supply Controls of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.
In addition, income tax laws relating to the Company may be changed in a manner which adversely affects us.
We are subject to numerous environmental and health and safety regulations that have become more stringent in recent years and may result in increased liabilities and increased capital expenditures by us.
Each of our segments is subject to the risk of incurring substantial costs and liabilities under environmental and health and safety laws and regulations. These costs and liabilities arise under increasingly stringent environmental and health and safety laws, including regulations and governmental enforcement policies and legislation, and as a result of third party claims for damages to property or persons arising from our operations. Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that pipelines, facilities and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of projects may require the submission and approval of environmental impact assessments and the implementation of mitigative measures prior to the implementation of such projects.
Failure to comply with environmental and health and safety laws and regulations may result in assessment of administrative, civil and criminal penalties, imposition of remedial obligations such as cleanup and site restoration requirements and liens and potentially, the issuance of injunctions to limit or cease operations. If we were unable to recover these costs through increased revenues, our ability to meet our financial obligations could be adversely affected.
The terminal and pipeline facilities that comprise our petroleum products pipeline system have been used for many years to transport, distribute or store petroleum products. Over time our operations, or operations by our predecessors or third parties not under our control, may have resulted in the disposal or release of hydrocarbons or wastes at or from these terminal properties and along such pipeline rights-of-way. In addition, some of our terminals and pipelines are located on or near current or former refining and terminal sites, and there is a risk that contamination is present on those sites. We may be subject to strict joint and several liability under a number of these environmental laws and regulations for such disposal and releases of hydrocarbons or wastes or the existence of contamination, even in circumstances where such activities or conditions were caused by third parties not under our control or were otherwise lawful at the time they occurred.
Further, the transportation of hazardous materials and/or other substances in our pipelines may result in environmental damage, including accidental releases that may cause death or injuries to humans, damage to third parties and natural resources, and/or result in federal and/or provincial civil and/or criminal penalties that could be material to our results of operations and cash flows.
We believe that we are in substantial compliance with existing legislation. However, environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. We cannot ensure
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that the costs of complying with environmental legislation in the future will not have a material adverse effect on our financial condition or results of operations. We anticipate that changes in environmental legislation may require, among other things, reductions in emissions to the air from our operations and result in increased capital expenditures. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition or results of operations. See Item 4B. “Business Overview” — for a summary of certain of the regulations affecting our business.
Our revenues from third-party customers are generated under contracts that must be renegotiated periodically and that allow the customer to reduce or suspend performance in some circumstances, which could cause our revenues from those contracts to decline.
Some of our contract-based revenues are generated under contracts with terms which allow the customer to reduce or suspend performance under the contract in specified circumstances, such as the occurrence of a catastrophic event to our or the customer’s operations. The occurrence of an event which results in a material reduction or suspension of our customer’s performance could reduce our profitability.
Many of our contracts with third-party customers for producer field services have terms of one year or less. As these contracts expire, they must be extended and renegotiated or replaced. We may not be able to extend, renegotiate or replace these contracts when they expire, and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. We face intense competition in our gathering, transportation, terminalling and storage activities. Other providers of crude oil gathering, transportation, terminalling and storage services that are able to supply our customers with those services at a lower price could reduce our ability to compete in this industry. Additionally, we may incur substantial costs if modifications to our terminals are required in order to attract substitute customers or provide alternative services. If we cannot successfully renew significant contracts or if we must renew them on less favorable terms, or if we incur substantial costs in modifying our terminals, our revenues from these arrangements could decline.
We may not have or be able to obtain adequate insurance to cover all risks incident to our business.
We currently maintain customary insurance of the types and amounts consistent with prudent industry practice; however, we are not fully insured against all risks incident to our business. We are not obliged to maintain any such insurance if it is not available on commercially reasonable terms. There can be no guarantee that such insurance coverage will be available in the future on commercially reasonable terms or at commercially reasonable rates or that the amounts for which we are insured, or the proceeds of such insurance, will compensate us fully for our losses. In addition, the insurance coverage obtained with respect to our business and facilities will be subject to limits and exclusions or limitations on coverage that are considered by management to be reasonable, given the cost of procuring insurance and current operating conditions. There can be no assurance that the insurance proceeds received by us in respect of a claim will be sufficient in any particular situation to fully compensate us for losses and liabilities suffered. If a significant accident or event occurs that is not fully insured, it could adversely affect our results of operations, financial position or cash flows.
Some of our employees are unionized and any work stoppages or unexpected increases in salary, wages and benefits could have an adverse effect on our financial results.
The largest components of our overall operating expenses are salary, wages, benefits and costs of contractors. Any significant increase in these expenses could impact our financial results. In addition, we are at risk if there are any labor disruptions. Our refinery facility located at Moose Jaw, Saskatchewan (“Moose Jaw”) is subject to a collective agreement with our employees at Moose Jaw and the Communications, Energy & Paperworkers Union of Canada, Local 595 (which expires on January 31, 2013) and certain Gibson Energy Partnership employees (operators and lab technicians at the Edmonton South and Hardisty terminals) are subject to an agreement with the Gibson Employees Association (which expires on December 31, 2013). Labor disruptions could restrict the ability of the asphalt plant or the terminal and pipeline operations to process crude oil or operate the terminals and pipelines and therefore affect our financial results. We attempt to enter into union negotiations on a timely basis in light of the length of the collective agreements. However, we cannot guarantee that we will be able to successfully negotiate collective agreements prior to their expiration. Any work stoppages or unbudgeted or unexpected increases in compensation could have a material adverse effect on our profitability.
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Our operations are dependent on technology and a breakdown of that technology could adversely impact the accuracy of our revenues and results of operations.
We are dependent on technology for certain of our operations. For example, if we were to lose functionality of our Supervisory Control and Data Acquisition System (“SCADA”) (due to loss of back-up power, servers, communication links or control interfaces), pipeline operations would cease due to loss of leak detection capability and we would no longer have the ability to receive, deliver, transfer or blend petroleum due to being unable to control valves and pumps and monitor flow rates and tank levels. The impact of short-term disruptions would typically be minimal due to the ability to re-schedule the planned activities and use spare capacity. Disruptions of longer duration would likely result in a loss of revenue.
Some of our storage tanks and portions of our pipeline system have been in service for several decades, and our operating and maintenance capital costs could increase due to aging equipment.
Operating and capital costs of our refinery, terminals and pipelines may vary considerably from our current and forecast values and rates and represent significant components of the cost of providing service. Our pipeline and storage assets are generally long-lived assets. As a result, some of those assets have been in service for several decades. The age and condition of these assets could result in increased maintenance or remediation expenditures. In general, as equipment in our facilities ages, maintenance capital expenditures and maintenance expenses with respect to such equipment may increase over time. In addition, certain of our facilities are presently operating at lower throughputs than their respective licensed capacities, and certain facilities will require expenditures for equipment refurbishment, replacement or debottlenecking in order to reach licensed capacity. Although operating costs are recaptured, in part, through the tariffs charged on volumes processed and transported, to the extent such charges escalate, producers may seek lower cost alternatives or stop production of their products. Consequently, our results of operations, financial position or cash flows may be adversely affected.
Our propane and NGL marketing and distribution segment depends on construction sector activity levels, which tend to be cyclical and which differ throughout the regions in which we operate.
Our results in propane distribution and sales depend heavily on residential, commercial and infrastructure construction activity and spending levels. The construction industry tends to be cyclical in the markets we serve. Construction activity and spending levels vary across our markets and are influenced by interest rates, inflation, consumer spending habits, demographic shifts, environmental laws and regulations, employment levels and the availability of funds for public infrastructure projects. Economic downturns may lead to recessions in the construction industry, either in individual markets or nationally, and may have a negative impact on our results of operations and cash flows.
Higher fuel prices could materially affect our results of operations and financial condition.
One of truck transportation segment’s largest operating expenses is fuel and while this cost is largely borne directly by our contract haulers, higher fuel prices could materially affect our results to the extent it impedes the ability of our contract haulers to provide us with transportation services. If we are unable to pass on these increased operating costs to our customers through the use of fuel surcharge programs, our results of operations and financial condition could be materially affected.
Some of our planned facilities are jointly owned by third parties and it may not be possible for us to obtain approval from those third parties for expansion projects which may adversely affect our ability to expand in the future.
One of our planned facilities is jointly owned with third parties. Approvals must be obtained from such joint owners for proposals to make capital expenditures regarding such facilities. These approvals typically require that a capital expenditure proposal be approved by the owners holding a specified percentage of the ownership interests in the relevant facility. It may not be possible for us to obtain the required levels of approval from co-owners of facilities for future proposals for capital expenditures, which may adversely affect our ability to expand or improve our jointly-owned facilities. In addition, agreements for joint ownership often contain restrictions on transfer of an interest in a facility. The most frequent restrictions
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require a transferor who is proposing to transfer an interest to offer such interest to the other holders of interests in the facility prior to completing the transfer. Such provisions may restrict our ability to transfer our interests in facilities or to acquire partners’ interests in facilities, and may also restrict our ability to maximize the value of a sale of our interest.
As part of our effort to minimize these risks, we maintain communication with our co-owners through participation in operating committees and formal decision-making processes. We also utilize our knowledge of industry activity and relationships with other owners to mitigate the risk of uncooperative behavior. However, there is no guarantee that we will be able to proceed with our plans for any facilities which are jointly owned.
Our operations may incur substantial costs to comply with future climate control legislation and regulatory initiatives.
The Federal Government of Canada has announced its intention to enact certain regulations in respect of greenhouse gases (“GHG”) and other pollutants. If enacted, these regulations may adversely affect our operations and increase our costs. These regulations may become more onerous over time as public and political pressures increase to implement initiatives that will reduce GHG emissions. There is also uncertainty as to the interplay between these federal regulations and the various provincial regulations with respect to GHG emissions.
In the Province of Alberta, regulations governing GHG emissions from large industrial facilities came into effect on July 1, 2007. The regulations apply to all facilities in Alberta that have produced 100,000 or more tonnes of carbon dioxide equivalent (“CO2e”) in 2003 or any subsequent year. None of our Alberta facilities produce emissions above the threshold of 100,000 tonnes of CO2e annually. We do not expect ongoing compliance costs associated with these regulations at our facilities to have a material adverse effect on our operations or financial condition; however, these and future regulations enacted by the Alberta Government may result in further regulatory requirements that could affect our business, but any such requirements are currently unknown. The Saskatchewan government is currently in a consultative process on new legislation respecting GHG emissions that, if enacted, could require emission reductions consistent with the federal regulatory plan under development. Regulations that may be enacted in Saskatchewan in respect of GHG reductions may have operational or financial adverse consequences for our business.
The U.S. Energy Independence and Security Act of 2007 precludes agencies of the U.S. federal government from procuring mobility-related fuels from non-conventional petroleum sources that have lifecycle GHG emissions greater than equivalent conventional fuel. This may have implications for our marketing in the United States of some heavy oil and oil sands production, but the impact cannot be determined at this time.
On May 13, 2010, the United States Environmental Protection Agency (“USEPA”) issued its GHG “tailoring rule” that would, in two phases, impose requirements upon the United States’ largest emitters of GHGs. In addition, a number of U.S. states and some Canadian provinces have formed regional partnerships to regulate emissions of GHGs. New legislation or regulatory programs that restrict emissions of GHGs in areas where we conduct business could adversely affect our operations and demand for our services. See Item 4.B. “Business Overview - Regulation” for a discussion of regulations affecting our business.
Certain private equity investment funds affiliated with Riverstone own 100% of our common shares and their interests may not be aligned with yours.
Riverstone indirectly owns 100% of the common shares of Gibson Energy Holding ULC, and, therefore, has the power to control our affairs and policies. Riverstone also controls, to a large degree, the election of directors, the appointment of management, the entering into mergers, sales of substantially all of our assets and other extraordinary transactions. The directors have authority, subject to the terms of our debt, to issue additional stock, implement stock repurchase programs, declare dividends and make other decisions. The interests of Riverstone could conflict with those of our Note holders. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of Riverstone, as equity holders, might conflict with the interests of our Note holders. Riverstone may also have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in their judgment, could enhance their equity investments, even though such transactions might involve risks to our Note holders. Additionally, Riverstone is in the business of making investments in companies, and may from time to time in the future acquire interests in businesses that directly or indirectly compete with certain portions of our business or are suppliers or customers of ours.
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If we fail to maintain proper and effective internal controls, our ability to produce accurate financial statements could be impaired, which could adversely affect our operating results, our ability to operate our business and investors’ views of us.
We must ensure that we have adequate internal financial and accounting controls and procedures in place so that we can produce accurate financial statements on a timely basis. We are required to spend considerable effort to establish and maintain our internal controls, which will be costly and time-consuming and will need to be re-evaluated frequently. We are required to comply with the requirements of the Sarbanes-Oxley Act of 2002 on December 31, 2011, but we have very limited experience in designing and testing our internal controls and we will incur significant costs in connection with first providing internal control reports. We are in the process of evaluating and, if appropriate, improving our internal controls and procedures, in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, which will require annual management assessments of the effectiveness of our internal control over financial reporting. We will be testing our internal controls and may identify areas for further attention and improvement. Implementing any appropriate changes to our internal controls may entail substantial costs to modify our existing financial and accounting systems, take a significant period of time to complete, and distract our officers, directors and employees from the operation of our business. These changes may not, however, be effective in maintaining the adequacy of our internal controls, and any failure to maintain that adequacy, or a consequent inability to produce accurate financial statements on a timely basis, could increase our operating costs and could materially impair our ability to operate our business. In addition, investors’ perceptions that our internal controls are inadequate or that we are unable to produce accurate financial statements may seriously affect the trading value of our Notes.
We have adopted new accounting standards in 2011, and this adoption may have a material impact on our financial statements.
In February 2008, Canada’s Accounting Standards Board confirmed that Canadian GAAP, as used by publicly accountable enterprises, will be fully converged to International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board. For our 2011 interim and annual financial statements, we will be required to report under IFRS and to provide IFRS comparative information for the 2010 fiscal year.
IFRS uses a conceptual framework similar to Canadian GAAP, but there are significant differences in recognition, measurement and disclosures. The adoption will result in changes to our reported financial position and results of operations, and these changes may be material. Moreover, the restatement of our 2010 financial statements for comparative purposes may be significant. For a summary of the material impacts identified by us to date, see Item 5. “Operating and Financial Review and Prospects - Management’s Discussion and Analysis of Financial Condition and Results of Operations”.
Litigation Risk
We are not a party to any material litigation. However, if any legitimate cause of action arose which was successfully prosecuted against us, our operations or results of operations could be adversely affected.
Risks Relating to the Notes
Our substantial indebtedness could adversely affect our financial health, restrict our activities and affect our ability to meet our obligations under the Notes.
As of December 31, 2010, we had a significant amount of indebtedness, including U.S.$760.0 million of long-term debt and $43.5 million of short term borrowings. Our substantial indebtedness could have important consequences such as:
· make it more difficult for us to satisfy our obligations with respect to the Notes;
· increase our vulnerability to and limit our flexibility in planning for, or reacting to, downturns or changes in our business and the industry in which we operate;
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· require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;
· restrict us from making strategic acquisitions or cause us to make non-strategic divestitures;
· place us at a competitive disadvantage compared to our competitors that have less debt; and
· limit our ability to borrow additional funds.
In addition, the terms of the indentures governing the Notes contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our debts.
The right to receive payments on the Senior Notes is effectively subordinated to the rights of our existing and future secured creditors. Further, the guarantees of the Senior Notes are effectively subordinated to all our guarantors’ existing and future secured indebtedness to the extent of the value of the assets securing such indebtedness.
Holders of our secured indebtedness will have claims that are prior to the claims of holders of the Senior Notes to the extent of the value of the assets securing that other indebtedness. Notably, we, and certain of our subsidiaries have obligations under the First Lien Notes, which are secured by liens on substantially all of our real property, personal property, plant and equipment and all of our equity interests and certain of our restricted subsidiaries. In addition, we and certain of our subsidiaries are parties to the Credit facility, which is secured by liens on substantially all of our working capital assets. The Senior Notes will be effectively subordinated to all of our secured indebtedness, including the First Lien Notes and our Credit facility. In the event of any distribution or payment of our assets (or the proceeds thereof) in any foreclosure, dissolution, winding-up, liquidation, reorganization, or other bankruptcy proceeding, holders of secured indebtedness will have prior claim to those of our assets that constitute their collateral and the proceeds thereof. Holders of the Senior Notes will participate ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as the Senior Notes including other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the Senior Notes. As a result, holders of Senior Notes may receive less, ratably, than holders of secured indebtedness.
Our leverage may limit our ability to borrow additional funds, comply with the terms of our indebtedness or capitalize on business opportunities.
Our leverage could have important consequences to investors in our Notes. We will require substantial cash flow to meet our principal and interest obligations with respect to the Notes and our other consolidated indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit facility to service our indebtedness, although the principal amount of the Notes will likely need to be refinanced at maturity in whole or in part. However, a significant downturn in the hydrocarbon industry or other development adversely affecting our cash flow could materially impair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We can give no assurance that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable.
Our leverage may adversely affect our ability to fund future working capital, capital expenditures, future acquisitions, or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.
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The First Lien Notes are not secured by certain excluded property and assets.
The First Lien Notes are not secured by certain excluded property and assets, including the Issuers’ working capital, receivables, inventory, investment property, most intangibles and contract rights and certain other assets (the “Credit facility collateral”) that are pledged for the benefit of the lenders under the Credit facility. Also, the collateral agent, on behalf of the holders of the First Lien Notes, is not able to control or direct any actions in respect of such other property, even if the rights of the holders of the First Lien Notes are adversely affected.
Any future pledges of collateral may be avoidable.
Any future pledge of collateral in favor of the collateral agent for the First Lien Notes might be avoidable by the pledgor (as debtor in possession) or by its trustee in bankruptcy or other third parties if the pledge or granting of the security interest is deemed a fraudulent conveyance, which is ordinarily evidenced by events or circumstances such as the pledgor being insolvent at the time of the pledge or granting of the security interest, the pledge permitting the holders of the First Lien Notes to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge or, in certain circumstances, a longer period.
The collateral is subject to casualty risks.
We are obligated under the collateral arrangements for the First Lien Notes to maintain adequate insurance or otherwise insure against hazards to the extent done by corporations operating properties of a similar nature in the same or similar circumstances. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. As a result, we cannot assure you that the insurance proceeds will compensate us fully for our losses. If there is a total or partial loss of any of the pledged collateral, we cannot assure you that any insurance proceeds received by us will be sufficient to satisfy all our secured obligations, including the First Lien Notes.
The collateral agent’s ability to exercise remedies is limited.
Each security agreement will provide the collateral agent on behalf of the holders of the First Lien Notes with significant remedies, including foreclosure and sale of all or a portion of the collateral. However, the rights of the collateral agent to exercise significant remedies (such as foreclosure) will be generally limited to a payment default, bankruptcy or the acceleration of the indebtedness, in each case, subject to certain exceptions.
The collateral securing the First Lien Notes includes substantially all of the equity interests of the Issuers. However, the Issuers and certain guarantors of the First Lien Notes are unlimited liability corporations. Shareholders of these companies are jointly and severally liable for any liability, default or other action of the unlimited liability corporation. Consequently, the willingness of the collateral agent to exercise rights and remedies against, or to enforce its security interest in, these equity interests will be significantly impaired. It may not exercise, or attempt to exercise, any rights of a shareholder in respect of an unlimited liability corporation without the risk of becoming a “shareholder.” In addition, there may be no opportunities to sell such collateral to any third party upon realization of the security interest in these equity interests.
Rights of holders of the First Lien Notes in the collateral may be adversely affected by the failure to perfect security interests in certain collateral or the perfection of liens on the collateral by other creditors.
The Issuers’ and the guarantors’ obligations under the First Lien Notes and guarantees are secured by a first priority lien on the collateral, subject to certain permitted liens. The collateral includes substantially all of the equity interests in the Issuers and certain of the Issuers’ subsidiaries and substantially all of the Issuers’ and our subsidiaries’ real property and equipment, whether now owned or, in certain cases, hereafter acquired, in each case, excluding the Credit facility collateral and subject to certain other exceptions. Applicable law requires, among other things, that certain property acquired after the grant of a general security interest can only be perfected at the time such property is acquired and identified. There can be no assurance that the trustee or the collateral agent will monitor, or that we will inform the trustee or the collateral agent of, the future
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acquisition of property that constitutes collateral, and that the necessary action will be taken to properly perfect the security interest in such after acquired collateral. Also, the trustee or collateral agent may fail to take action to perfect the security interest in such acquired collateral. Although such failure may constitute an event of default in respect of the First Lien Notes, in certain circumstances, it may not prevent such failure from resulting in the loss of the security interest in such newly acquired property or the loss of priority of the security interest in such property in favor of the holders of the First Lien Notes against other third party creditors.
We may also be unable to perfect the security interest granted to the holders of the First Lien Notes in certain of the collateral to the extent perfection cannot be effected through filings under the Uniform Commercial Code or the personal property security legislation of the applicable province or territory. To the extent that a security interest in any item of collateral is unperfected, in a bankruptcy the First Lien Note holders may not have greater rights to such collateral than our general unsecured creditors including the holders of our Senior Notes. In addition, the priority of the liens on any item of collateral securing the First Lien Notes would be determined by, among other things, the time of perfection of a security interest or charge in that collateral. In addition, under various laws, certain creditors, such as purchase money lenders, may be entitled to a prior claim to that of a person who has a previously perfected security interest in the item of collateral financed with the purchase money debt.
The collateral securing the First Lien Notes includes real property. Certain material owned real property is subject to fixed and specific charges registered in the appropriate land registries. However, the balance of real property (excluding properties held by non-guarantor subsidiaries), including the easements related to the rights-of-way for each of our pipelines, some of which may be considered material, is subject only to floating charges which are not registered in the appropriate land registries. The floating charges are subordinate to the holder of any registered interest in such real property (including, without limitation, easements and rights-of-way for pipelines) including any subsequent registered charges.
No consents or approvals, to the extent they may be required in connection with the granting of the floating charge over real property, plant and equipment, have been obtained (including with respect to any leases, easements, pipeline rights-of-way or similar rights); however in our view there are no such consents or approvals for which the failure to obtain would have a material adverse effect on the security being provided.
The collateral securing the First Lien Notes includes motor vehicles and trailers (serial number goods) of the Issuers and guarantors, subject to certain exceptions. The security interest in these serial number goods will be perfected under the personal property security legislation but the serial number of this equipment may not be added to the financing statements. Accordingly, the liens will be subordinate to the holders of security interests in such serial number goods which are perfected by adding the serial number to the filing, including any such subsequently perfected security interests in these serial number goods.
Furthermore, various statutory liens and deemed trusts created under provincial and Canadian federal legislation may, as a matter of law, have priority over the liens securing the First Lien Notes.
Fixed charge mortgages are registered against only five of our owned real properties for which title insurance policies were obtained. Other than such five properties, there can be no assurance therefore that the mortgages securing the First Lien Notes are encumbering the correct real properties and that there are no liens other than those permitted by the indenture governing the First Lien Notes encumbering our owned real properties.
In connection with the issuance of our First Lien Notes, we were not required to provide surveys with respect to our owned real properties that constituted collateral for the First Lien Notes. As a result, other than pursuant to the title insurance obtained for such five properties, there is no independent assurance that, among other things, (i) the real property included any or all of the property owned by us and our guarantors that it was intended to include and (ii) no encroachments, adverse possession claims, zoning or other restrictions existed with respect to such owned real properties, which could result in a material adverse effect on the value or utility of such owned real properties.
We were not required to provide title opinions with respect to our owned real property. In addition, we were not required to provide title insurance with respect to our owned real property, other than five of our owned real properties located in Edmonton, Hardisty, Lloydminster, Surrey and Moose Jaw. As a result, other than pursuant to the title insurance policies
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issued for such five properties, there was no independent assurance that, among other things, we own the rights to the owned real properties and that our title to such owned real property is not encumbered by liens not permitted by the indentures governing the Notes.
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Despite current indebtedness levels, we and our subsidiaries may still be able to incur substantially more debt, including additional secured indebtedness. This could further exacerbate the risks associated with our substantial financial leverage.
The terms of the indentures governing the Notes permit us to incur substantial additional indebtedness in the future, including additional secured indebtedness. If we incur any additional indebtedness that ranks equal to the First Lien Notes, the holders of that debt will be entitled to share ratably with the holders of the First Lien Notes in any proceeds distributed in connection with any foreclosure upon the collateral (in the case of all indebtedness secured on an equal and ratable basis with the First Lien Notes) or any insolvency, liquidation, reorganization, dissolution or other winding up of us (in the case of all indebtedness ranking equal to the First Lien Notes). If we incur any additional indebtedness that ranks equal to the Senior Notes, the holders of that debt will be entitled to share ratably with holders of the Senior Notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding up of us (in the case of all indebtedness ranking equal to the Senior Notes). In addition, the agreements governing our Credit facility permit additional borrowing. Any additional secured debt will rank senior to the Senior Notes and the subsidiary guarantees to the extent of the value of the assets securing such debt, including the First Lien Notes and our Credit facility. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify.
To service our indebtedness, we will require a significant amount of cash and our ability to generate cash depends on many factors beyond our control.
Our ability to make payments on and to refinance our indebtedness, including the Notes and our Credit facility, and to fund planned capital expenditures and maintain sufficient working capital will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.
Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our Credit facility will be adequate to meet our future liquidity needs for at least the next year.
We cannot assure you, however, that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our Credit facility in an amount sufficient to enable us to pay our indebtedness, including the Notes, or to fund our other liquidity needs. If our cash flows and capital resources are insufficient to allow us to make scheduled payments on our indebtedness, we may need to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance all or a portion of our indebtedness, including the Notes, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including the Notes and our Credit facility, on commercially reasonable terms or at all, or that the terms of that indebtedness will allow any of the above alternative measures or that these measures would satisfy our scheduled debt service obligations. If we are unable to generate sufficient cash flow or refinance our debt on favorable terms, it could significantly adversely affect our financial condition, the value of our outstanding debt and our ability to make any required cash payments under our indebtedness.
We may not have the ability to raise funds necessary to finance any change of control offer required under the indentures.
If a change of control, as defined in each of the indentures governing the Notes occurs, we will be required to offer to purchase each series of the Notes at 101% of their principal amount plus accrued and unpaid interest. If a purchase offer obligation arises under the indentures, a change of control could also have occurred under the Credit facility, which could result in the acceleration of the indebtedness outstanding thereunder. Any of our future debt agreements may contain similar restrictions and provisions. If a purchase offer were required under an agreement governing our debt, we may not have sufficient funds to pay the purchase price of such debt, including the Notes, that we are required to purchase or repay.
Canadian insolvency laws may adversely affect a recovery by holders of the Notes.
We, the Issuers and certain of the guarantors of the Notes are unlimited liability corporations or corporations incorporated under the laws of the Province of Alberta, British Columbia and Saskatchewan, Canada. The ability of the holders of Notes to
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realize upon the assets of Gibson Energy ULC, Gibson Energy Holding ULC and the Canadian guarantors may be subject to certain bankruptcy and insolvency law limitations in the event of the bankruptcy or insolvency of any of these entities.
Canadian insolvency legislation of general application is federal. It consists of the Bankruptcy and Insolvency Act (Canada) (the “BIA”), the Winding up and Restructuring Act (Canada) (the “WURA”) and the Companies’ Creditors Arrangement Act (Canada) (the “CCAA”). Under the BIA and the WURA, the assets of an insolvent company may be liquidated subject to the rights of secured creditors and the proceeds distributed to ordinary creditors who have proved claims against the debtor company. Alternatively, each of the BIA, the CCAA and the WURA permits an insolvent company to obtain a stay of proceedings and restructure its obligations to creditors subject to court supervision and the provisions of those statutes. Under the BIA and the CCAA, a restructuring of the obligations of the debtor company must be approved by a majority in number representing two-thirds in value of each class of creditors affected by the restructuring and, if approved by the relevant Canadian court, the restructuring would be binding on all creditors (including the dissenting minority) within any class with requisite majority approval. Under the WURA, the requirement for approval is a majority in number representing three-quarters in value of each class of creditors affected by the restructuring.
If it applies, the CCAA is often the statute of choice. Under the CCAA, an insolvent company applies to the court for an order obtaining a temporary stay of proceedings against it by creditors and other persons dealing with the company of up to 30 days, which can be extended by the court, in order to permit the debtor to prepare and file a proposal or plan of arrangement for consideration by all or some of its creditors to be voted on by the various classes of its creditors affected thereby, and thereafter seek approval and implement such plan. The CCAA requires that a court officer be appointed to monitor the affairs of the debtor company while it is under court supervision and to report to the court on the state of the debtor company’s business and financial affairs, including any material adverse change therein while the debtor company is under court protection. Subject to orders of the court either increasing the powers of the monitor or appointing an interim receiver, the debtor company and its management remain in possession and control of the assets of the debtor company while it is under court protection. Secured creditors would be prevented from exercising remedies based on defaults under their security without court approval.
The powers of the court under the BIA and particularly under the CCAA have been exercised broadly to protect a restructuring entity from actions taken by creditors and other parties. Accordingly, we cannot predict if payments under the Notes would be made following commencement of or during such proceeding, whether or when the collateral agent could exercise its rights under the indenture and the collateral documents governing the First Lien Notes, or whether and to what extent holders of the Notes would be compensated for any delays in payment, if any, of principal, interest and costs, including the fees and disbursements of the collateral agent.
Because several of our directors and officers reside in Canada, the holders of the Notes may not be able to effect service of process upon them or enforce civil liabilities against them under the U.S. federal securities laws.
Gibson Energy ULC and Gibson Energy Holding ULC are unlimited liability corporations organized under the laws of the Province of Alberta and governed by the applicable provincial, territorial and federal laws of Canada. Several of our directors and officers named in this Form 20-F reside principally in Canada. Consequently, it may be difficult to effect service of process within the United States upon those persons. In addition, there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the U.S. federal securities laws and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against us or our directors and officers named in this Form 20-F.
If there is a foreclosure on the collateral securing the First Lien Notes, you may be subject to claims and liabilities under environmental laws and regulations.
Lenders that hold a security interest in real property may be held liable under environmental laws for the costs of remediating or preventing releases or threatened releases of hazardous materials at or from the mortgaged property. While lenders that neither foreclose on nor participate in the management of a mortgaged property generally have not been subject to liability, lenders that take possession of a mortgaged property or that participate in the management of a mortgaged property may be liable for such costs of remediation and must carefully and strictly adhere to federal and provincial laws to avoid other environmental liability. In this regard, the trustee for the First Lien Notes would need to evaluate the impact of these potential
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liabilities before determining to foreclose on the mortgaged properties securing the First Lien Notes and exercising other available remedies. In addition, the collateral agent may decline to foreclose upon the mortgaged properties or exercise other remedies available to the extent that it does not receive indemnification to its satisfaction from the holders of the First Lien Notes.
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Federal, state and provincial laws allow courts, under certain circumstances, to void guarantees and require Note holders to return payments received from guarantors.
The Notes are guaranteed by all of our material subsidiaries. The guarantees may be subject to review under U.S. federal bankruptcy law and comparable provisions of state fraudulent conveyance laws and Canadian federal insolvency laws and provisions of provincial preference, fraudulent conveyance and corporate laws, if a bankruptcy or insolvency proceeding or a lawsuit is commenced by or on behalf of us or one of our guarantors or by our unpaid creditors or the unpaid creditors of one of our guarantors. Under these laws, a court could void the obligations under the guarantee, subordinate the guarantee of the Notes to that guarantor’s other debt or take other action detrimental to the holders of the Notes and the guarantees of the Notes, if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee:
· issued the guarantee to delay, hinder or defraud present or future creditors;
· received less than reasonably equivalent value or fair consideration for issuing the guarantee at the time it issued the guarantee;
· was insolvent or rendered insolvent by reason of issuing the guarantee;
· was engaged, or about to engage, in a business or transaction for which its remaining assets constituted unreasonably small capital to carry on its business;
· intended to incur, or believed that it would incur, debts beyond its ability to pay as they mature; or
· with respect to Canadian companies in issuing the guarantee, acted in a manner that was oppressive, unfairly prejudicial to or unfairly disregarded the interests of any shareholder, creditor, director, officer or other interested party.
In those cases where our solvency or the solvency of one of our guarantors is a relevant factor, the measures of insolvency will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a party would be considered insolvent if:
· the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;
· the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing indebtedness, including contingent liabilities, as they become absolute and mature; or
· it could not pay its indebtedness as it becomes due.
We cannot be sure as to the standard that a court would use to determine whether or not a party was solvent at the relevant time, or, regardless of the standard that the court uses, that the issuance of the guarantees would not be voided or the guarantees would not be subordinated to the guarantors’ other debt. If such a case were to occur, the guarantee could also be subject to the claim that, since the guarantee was incurred for our benefit and only indirectly for the benefit of the guarantor, the obligations of the applicable guarantor were incurred for less than fair consideration.
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Item 4. Information on the Company
4.A. HISTORY AND DEVELOPMENT OF THE COMPANY
The origins of Gibson date back to 1950 with the incorporation of Gibson Petroleum Marketing Co. Ltd., which started marketing petroleum products in 1953. In 1954, Gibson entered the pipeline business with the creation of Gibson Crude Oil Purchasing Co. Ltd. and the construction of a pipeline gathering system in Alberta. In 1957, Gibson built its first oil terminal facility in Hardisty, Alberta, connected into the Interprovincial Pipeline moving oil from western Canada to the east. In 1955, Gibson began its oil trucking operations, and subsequently expanded these operations throughout western Canada, through organic growth and various acquisitions. In 1982, Gibson entered the fractionation business with the construction of its Hardisty fractionation facility to process NGLs into their component products, propane, butane, condensate and ethane. In 1988, Gibson entered the propane business with the purchase of James Propane, followed by the purchase of Canwest Propane in 1990, and expanded its propane operations throughout Alberta, Saskatchewan and British Columbia. Through its purchase of Link Petroleum in 1998 and the purchase of MP Energy in 2007, Gibson entered into the wholesale propane distribution and marketing business, which has subsequently expanded to include propane terminals and storage facilities in Ontario, British Columbia, Washington, Montana and North Dakota. In 2002, Gibson entered the refining business with the purchase of a refinery in Moose Jaw, Saskatchewan which is strategically connected to pipelines and contains significant product storage capacity. Gibson subsequently expanded the refinery to year-round operations and through different process applications and expansions, the refinery now manufactures paving and roofing flux asphalt as well as wellsite fluids used by the petroleum industry.
On December 12, 2008, Gibson Acquisition ULC, an indirect wholly owned subsidiary of Co-op investment funds affiliated with Riverstone, acquired all of the issued and outstanding shares of Gibson Energy Holdings Inc. from Hunting. From Gibson’s inception to the Acquisition, the Company had been controlled by Hunting, a UK-based energy services company publicly listed on the London Stock Exchange. Following the Acquisition, Gibson Energy Holdings Inc. through a series of amalgamations, was amalgamated with Gibson Acquisition ULC to form Gibson Energy ULC.
In the year ended December 31, 2010, we completed the two largest acquisitions in our history. On May 14, 2010, we purchased Taylor Logistics LLC and substantially all of the assets of Taylor Propane Gas Inc (collectively, “Taylor”), 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. On August 25, 2010, we acquired the remaining 75% interest in Battle River Terminal ULC (“ BRT”), which is comprised of four 300,000 barrel tanks and related infrastructure that is now part of our Hardisty Terminal. These acquisitions expand our geographic reach as they resulted in expanding our service offerings in key hydrocarbon producing regions throughout the United States and significantly expanded the terminal operations at our Hardisty Terminal.
Our principal executive offices are located at 1700, 440-2nd Ave S.W., Calgary, Alberta T2P 5E9, Canada. Our telephone number at this address is +1.403.206.4000.
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4.B. BUSINESS OVERVIEW
We are one of the largest independent midstream energy companies in Canada and a major participant in the crude oil transportation business in the United States, and are engaged in the movement, storage, blending, processing, marketing and distribution of crude oil, condensate, natural gas liquids, and refined products. We transport hydrocarbons by utilizing our integrated network of terminals, pipelines, storage tanks, and truck fleet located throughout western Canada and the United States. We are also involved in the processing, blending and marketing of hydrocarbons and are the second largest retail propane distribution company in Canada. Our integrated operations allow us to participate across the full midstream energy value chain, from the hydrocarbon producing regions in Canada and the United States, through our strategically located terminals in Hardisty and Edmonton, Alberta and injection stations in the United States, to the refineries of North America via major pipelines.
We have provided market access to leading oil and gas industry participants in western Canada for the last 58 years. We have grown our business by diversifying our service offerings to meet customers’ needs and by expanding geographically. Most recently, we expanded our service offerings to key hydrocarbon producing regions throughout the United States to position us as a North American midstream energy company.
Our five integrated business segments are as follows:
· Terminals and pipelines: We provide fee-based storage and terminalling services and tariff-based pipeline services for crude oil, condensate and refined products. Over the last five years, we have transported an average of over 303,000 barrels per day through our integrated logistics assets. This business segment includes the owned and operated Hardisty Terminal and Edmonton South Terminal, both of which are located at principal hubs for aggregating and exporting oil and refined products out of the WCSB. The segment also includes approximately 263 miles of pipeline and seven custom terminals, as well as 71 pipeline injection stations located in the United States;
· Truck transportation: We offer hauling services for crude, condensate, propane, butane, asphalt, methanol, sulfur, petroleum coke, gypsum and drilling fluids to many of North America’s leading oil and gas producers in western Canada and the United States. In the year ended December 31, 2010, we transported over 150 million boe throughout Canada and the United States, assuming a full year impact from Taylor. We own approximately 2,000 trailers and have access to approximately 1,160 tractors through a combination of Company-owned tractors and contractual arrangements with over 550 owner-operators and lease operators in Canada and the United States;
· Propane and NGL marketing and distribution: We are the second largest retail propane distribution company in Canada via our branded Canwest Propane business. In the year ended December 31, 2010, Canwest Propane sold over 68 million gallons of propane to oil and gas, industrial and residential customers. We are also one of Canada’s largest wholesale propane distributors with six propane storage terminals, selling over 227 million gallons of propane in 2010. We also operate an NGL marketing business that sold approximately 6.0 million barrels in the year ended December 31, 2010, assuming a full year impact from Taylor. We also operate a fractionation plant located at our Hardisty Terminal that processes NGLs into its component products such as condensate, butane, propane, ethane and solvents;
· Processing and wellsite fluids: We refine and market a variety of products, including several grades of road asphalt, roofing flux, wellsite fluids and tops (a bottomless light sour crude oil, a residual from the asphalt refining process, which is a premium feedstock for refiners and which is also used for blending). This business segment’s primary asset is a 16,000 barrel per day oil refinery located in Moose Jaw, Saskatchewan; and
· Marketing: We provide marketing services to our customers by leveraging our extensive asset network of terminals, pipelines and trucks. Our asset network allows us to capitalize on specific location, quality, or time-based arbitrage opportunities. We purchase, sell, store and blend crude oil and condensate, selling approximately 129,000 physical barrels per day in the year ended December 31, 2010.
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Business Strategies
As we move energy products through our facilities utilizing our terminals, pipelines, tank storage and truck transportation fleet in concert with our marketing, processing and blending capabilities, we look to create value through our synergistic service offerings. Our primary objective is to generate stable and growing cash flows for our shareholder, which we plan to accomplish by executing on the following business strategies:
· Leverage our integrated asset base to capture inter-division synergies within the hydrocarbon value chain. The location of our assets combined with the integration of our business segments enable us to participate in the full hydrocarbon value chain, generating profits on the commodities we touch all the way from the wellhead to the ultimate market. By spanning the entire value chain, we are able to provide efficient, reliable service to both producers and end-users while deriving revenue and cost synergies through our integrated network of terminals, pipelines, processing facilities, truck transportation and distribution network. For example, our terminal and pipelines and truck transportation segments earn increased revenues as a result of activities within our marketing segment. Our marketing segment purchases crude oil from the wellhead and utilizes our truck transportation services to deliver it to our terminals, which in turn results in increased revenues in the truck transportation and terminals and pipelines segments as a result of additional storage and throughput fees. Another example is that we believe the margins in the processing and wellsite fluids segment are higher and more stable since we can transport our refinery feedstock, purchased by our marketing segment, via our truck transportation segment and by rail to our own interim storage which allows us to minimize transportation costs and to service our customer base with just-in-time delivery. The provision of an extended suite of services also benefits our customers as it provides them with a one-stop solution, thereby simplifying their operations.
· Partner with high quality customers, including major oil companies, to provide us with long-term stable revenue streams. We have historically entered into long-term contracts that provide stable revenues for our asset base, in particular for our terminal operations. In the year ended December 31, 2010, we entered into long-term service agreements with major investment grade oil companies that provide us with fixed fee based storage and terminalling revenues along with the ability to earn additional fees above certain volumes. With our increased tankage at our Hardisty Terminal as a result of the acquisition of the remaining 75% equity interest in BRT and our undeveloped land holdings at our Hardisty and Edmonton South terminals, we will continue to focus on developing and maintaining long-term strategic relationships that provide both stable revenues and maximum throughput at our facilities. In addition, we will continue to focus on maintaining and increasing long-term arrangements throughout our suite of services.
· Expand our network of assets. We believe that we are well-positioned to capitalize on the numerous organic growth opportunities that are evolving in North America due to the significant increase of expected production in the WCSB, as well as the emerging liquids rich basins in the United States, such as the Niobrara, Eagle Ford and Bakken oil and gas plays. We have meaningfully expanded our platform and positioned ourselves to take advantage of future industry activity through our increased and available capacity. By leveraging off of our existing asset network throughout North America, we believe there remains a significant number of organic expansion opportunities similar to those we commenced in the year ended December 31, 2010 within our terminals and pipelines segment, such as the construction of a 300,000 barrel tank at the Hardisty Terminal and the construction of the Hardisty West Terminal (as defined herein) on 26 acres of our undeveloped land position.
· Pursue strategic acquisition opportunities consistent with past practices. We have a long track record of pursuing strategic acquisitions that we believe will benefit our business, either by expanding our reach in existing markets or by providing platforms with which to enter new markets such as our expansion into the U.S. with our acquisition of Taylor. We will continue to seek acquisitions which we feel will allow us to successfully expand our business, both in existing markets and in new markets. Specifically, we seek to identify bolt-on opportunities in our existing segments where we can drive higher volumes or greater operating efficiencies due to our existing infrastructure, customer relationships and management expertise.
· Maintain discipline when investing in new equipment, technology, facilities and personnel. We plan to continue our historical practice of deploying capital in a disciplined manner to grow our business and improve upon our existing
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operations. We have focused on investing capital on both physical assets and personnel, and we plan on continuing this practice going forward. We make capital investment decisions principally by analyzing metrics such as the projected return on gross capital employed, internal rate of return, net present value and discounted cash flows whether this involves equipment, technology or facilities.
· Maintain sound risk management policies. We have a long history of conservative risk management and intend to continue this practice in the future. We aim to minimize our exposure to commodity prices by continually hedging our physical commodity inventory using both physical and financial contracts. We only enter into financial contracts with investment grade counterparties. Our board-approved policy is to have no more than $7.0 million of Value at Risk (“VAR”) at any time, with no one individual commodity having a sublimit of more than $2.5 million. These VAR limits have not been changed in over five years. In the year ended December 31, 2010, our Company-wide daily VAR limit did not exceed $2.2 million. By conservatively managing our commodity exposure, our marketing segment has delivered annual profitable results in each of the past 15 years.
· Continue award-winning health, safety, security and environmental programs. In addition to financial risks, we are subject to a number of health, safety, security and environmental risks. Proactively managing these risks is critical to complying with government regulations, maintaining the high standards expected by our customers and creating an attractive and safe work environment for our employees. We have been recognized for having leading health, safety, security and environmental practices in the past, and are committed to continued high standards in the future. Our record on health, safety, security and environmental matters allows us to do business with the most discriminating market participants.
Our Operating Segments
Terminals and pipelines
Business Overview
Our terminals and pipelines segment includes the Hardisty and Edmonton South Terminals, approximately 263 miles of pipeline, seven custom terminals in Alberta and Saskatchewan, and 71 pipeline injection stations located near key hydrocarbon producing regions throughout the United States. The storage and terminalling facilities, which provide fee based services, have an aggregate storage capacity of approximately 3.3 million barrels and throughput averaging approximately 384,000 barrels per day in 2010. The pipeline facilities, which provide tariff-based services, have capacity of over 90,000 barrels per day. Our custom terminals generate profits by purchasing various grades of crude oil and condensate and blending them to capture arbitrage opportunities when they exist.
The Hardisty Terminal receives product from the Gibson-owned Bellshill and Provost pipelines, and has receipt and delivery connections to most major pipelines in the area. The Edmonton South Terminal has receipt and delivery connections to major pipelines in the area including pipeline receipts from Suncor’s Edmonton and Fort McMurray refineries. We operate our Hardisty Terminal as a third party shipper facility and have the flexibility to receive from and ship to all of the major pipelines that intersect at Hardisty. Since we are able to provide customers this flexibility and are indifferent about which pipeline the crude is delivered to, we have a competitive advantage over some of the other terminals in the Hardisty area. In addition to pipeline receipts, crude oil and condensate are trucked into all terminals. By having large and strategic undeveloped centrally located land holdings in the Edmonton and Hardisty areas we are uniquely positioned to participate in the expected infrastructure build-out necessary to support oil and gas industry growth in the WCSB.
Tariffs at the terminals depend upon product density, volume, demand for terminalling, terms of the contract and available tankage. Fees earned at the injection stations are primarily throughput fees. Tariffs and other fees on our pipeline systems vary by receipt point and delivery point. The terminals and pipelines business relies on both long-term and short term contracts. Long-term contracts are typically fixed fee arrangements where customers pay throughput fees regardless of the volumes delivered, or pay fees associated with dedicated tank usage or both. In addition to the fixed fee components, we can earn additional usage fees above certain volume thresholds. For the year ended December 31, 2010, approximately 86% of the segment’s external revenue (excluding custom terminal revenue) was from fee based revenue, of which 35% was long-term fixed fee revenue.
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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 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 pipelines.
The following table contains information regarding our terminals and pipelines operations:
Asset | | Key Attributes |
| | |
Hardisty Terminal | | · Approximately 2.8 million barrels of storage with approximately 188,000 barrels per day of average throughput in 2010 · Approximately 2.0 million barrels of storage are for dedicated customer use under long-term arrangements that provide for fixed monthly fees, plus additional usage fees based on throughput |
| | |
| | · Truck loading and offloading, crude blending and cooling, storage and receipt and delivery services into Keystone, Enbridge, Express and IPF Southbound pipelines · Approximately 184 acres of undeveloped land available for future expansion opportunities |
| | |
Edmonton South Terminal | | · Approximately 460,000 barrels of storage connected to the major export pipelines operated by Enbridge and Kinder Morgan, approximately 48,000 barrels per day of average throughput in 2010 |
| | |
| | · Handles diesel fuel, LPGs, wellsite fluids and crude oil |
| | |
| | · Serviced by Canadian Pacific and Canadian National rail systems, four existing pipeline connections, truck loading and offloading · Approximately 45 acres of undeveloped land available for future expansion opportunities |
| | |
Custom Terminals | | · Seven terminals throughout Alberta and Saskatchewan |
| | |
| | · Typically blend smaller batches of crude grades which are transported to the terminals by truck transportation and injected into pipeline systems |
| | |
Provost Pipeline | | · Approximately 175 miles of pipe extending east from the Hardisty Terminal, with 50,000 barrels per day capacity |
| | |
Bellshill Lake Pipeline | | · Approximately 70 miles of pipe extending west from the Hardisty Terminal with 30,000 barrels per day capacity |
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Injection Stations | | · 71 injection stations throughout the United States, primarily in Louisiana, Texas, Oklahoma, Wyoming, Montana and North Dakota |
| | |
Equity Investment | | · Approximate 39% equity interest in Palko Environmental Ltd.(“Palko”), a Canadian-listed company · Palko provides hydrocarbon waste management and resource recovery solutions to the upstream and midstream oil and gas industry in western Canada |
The Hardisty Terminal, Edmonton South Terminal, Hardisty fractionation plant and the Bellshill and Provost Pipeline facilities are all controlled by our Supervisory Control and Data Acquisition (“SCADA”) system, which is operated out of a
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central control room staffed with operators 24 hours per day, 7 days per week. The SCADA system allows the control room operators to control the various equipment at each of the facilities including opening/closing valves, turning pumps on and off as well as, for example, selecting the speed of certain pumps, directing product to or from the appropriate tank and adjusting blending ratios. The SCADA system also acquires data from all aspects of each facility’s operation which data is stored for future reference and/or used immediately for the safe and efficient operation of the facilities. Some examples of this data are pressures, temperatures, volumes, flow rates and tank levels. This information enables the SCADA system to, among other things, perform volume balance calculations to quickly detect pipeline volume imbalances and alert the operators to take action. Overall, the SCADA system allows for timely and efficient operation as well as assists us in performing various regulatory compliance functions.
Our terminals and pipelines segment provided approximately 1%, 1% and 3% of our revenues and 24%, 29% and 27% of our segment profit for the years ended December 31, 2010, 2009 and 2008, respectively.
Customers
We provide fee-based storage and terminalling services and tariff-based pipeline services to independent and integrated oil companies and petroleum marketing companies. End users for our products in the terminals and pipelines segment are primarily refiners with product reaching the end markets via major export pipelines to which we are connected. In the year ended December 31, 2010, three primary customers together accounted for approximately 36% of revenue from our terminals and pipelines segment. The largest customer accounted for 21% and the second and third largest customers accounted for 9% and 6% of revenue, respectively. Approximately half of the revenues with these three investment grade customers are subject to long-term contracts. Some of the major customers of this segment are Husky, Suncor, ConocoPhillips, Nexen and Cenovus.
Competition
Certain major pipeline companies have existing storage facilities connected to their systems that compete with certain of our storage facilities. Competition among terminals is based on location and connectivity of assets and the range of services provided.
Competition among pipelines is based primarily on transportation charges, availability of service to producing areas and access to specific crude oil blend streams by the owners of the crude oil. We believe that the maturity of producing oilfields, capital requirements, environmental considerations and the difficulty in acquiring rights-of-way and related permits make it unlikely that competing pipeline systems comparable in size and scope to our pipeline systems will be built in the foreseeable future. Trucking services may also compete for crude oil volumes and this competition places a ceiling on the transportation charges a pipeline can levy.
Integration
By operating a network of terminals and injection stations, we are able to provide exclusive delivery points for our truck transportation operations as our terminals and injection stations will only accept crude oil trucked in by a Gibson operated truck. This provides a competitive advantage to our truck transportation operations and also ensures that the necessary safety, security and environmental policies are controlled by us. In addition, the terminals provide our marketing operations with priority access to the Gibson owned and operated terminal infrastructure thereby enabling the marketing segment to capitalize on quality or time-based arbitrage opportunities.
Truck transportation
Business Overview
Our truck transportation segment is one of the largest truck haulers of crude, condensate, propane, butane, asphalt, methanol, sulfur, petroleum coke, gypsum and drilling fluids in North America, moving over 150 million boe throughout Canada and the United States in the year ended December 31, 2010, assuming a full year impact from Taylor. On a daily basis, a significant amount of crude oil produced in Canada requires transport by truck. As a result, trucking is considered to be a critical component for the movement of crude oil in North America. Through our 55 years of trucking experience, we have
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developed a reputation for reliable, safe and on-time service delivery enabling us to maintain long-term customer relationships with many oil and gas companies. These relationships allow us to grow alongside these companies as demand for crude oil hauling services should increase as overall production grows. In addition, our large flexible fleet makes us a “first-call” supplier when pipeline disruptions occur. These hauls, referred to as spot movements since they are not long-term hauls, can attract premium pricing. In addition to hauling, we also generate revenues from the sale of chemicals to the natural gas processing industry.
We own approximately 2,000 trailers and have access to approximately 1,160 tractors through a combination of Company-owned tractors and contractual arrangements with over 550 owner-operators and lease operators in Canada and the United States. Our contracts with the Canadian tractor owner-operators stipulate that fuel and maintenance costs related to the tractors are covered by the owner-operators. Our contracts with lease operators in the United States stipulate that lease operators cover all maintenance and repair costs for both the tractor and trailer units, which are owned by us, as well as all fuel for the truck. Under the Canadian and U.S. agreements the owner-operators and lease operators, as applicable, are entitled to a percentage of the revenues generated by the hauling services they provide. In addition, we provide administration services, including accounting, insurance, and a health benefit program. The costs of these programs are borne by the owner-operators or the lease operators, as applicable.
Our large scale and comprehensive fleet allows us to carry out logistically complex high margin jobs, regardless of the volume or destination. We consistently provide timely and safe delivery of petroleum feedstocks and products to customers through our base locations situated throughout western Canada and the United States.
Our truck transportation segment conducts its business using a combination of long-term contracts, master service agreements, tenders that range between one and two year periods and short-term evergreen contracts with a cancellation notice period typically 30 days. We have a long-term agreement with Shell requiring Shell to use Taylor as its exclusive transportation provider in the United States and to operate certain injection stations exclusively for Shell. Transportation rates vary based on receipt point, delivery point, length of haul and product hauled. Also, hauls can be regularly scheduled under service agreements or hauled as spot movements. Of the revenue generated by this segment in the year ended December 31, 2010, long-term contracts, and tender related agreements accounted for 25% and 28% of the segment’s revenue, respectively.
Our truck transportation segment provided approximately 8%, 5% and 6% of our revenues and 31%, 21% and 29% of our segment profit for the years ended December 31, 2010, 2009 and 2008, respectively.
Customers
Our customers in the truck transportation segment include oil and gas exploration and production companies, refiners, oilfield drilling contractors, road construction companies and LPG and refined product marketing companies. Our three largest external customers, each investment grade, together accounted for approximately 32% of segment revenue in the year ended December 31, 2010, with the largest customer accounting for 17%. The truck transportation segment’s significant customers include Shell, Canadian Natural Resources, Devon, PetroBakken Energy, Suncor, and Japan Canada Oil Sands.
Competition
We face competition that varies by both product and geography with no one company having the same service offerings across the geographic areas that we service. Price competition increases in periods of lower activity across all products and all geographies, and the inverse is true when activity levels peak. Any changes in the level of price competition have a potential impact on net hauling margin which ultimately impacts overall segment profit. However, we believe that we have a competitive advantage over some of our competitors as our health, safety, security and environmental policies are robust enough to meet the stringent requirements of our largest customers.
Integration
Our truck transportation segment’s unique integration with our other operating segments positions it to optimize our overall assets to increase profitability and cash flows. In particular, the truck transportation assets allow our marketing operations to take advantage of arbitrage opportunities where the marketing group utilizes Gibson trucks when making spot purchases from
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the wellhead and then delivers these purchases to our terminals, which in turn results in additional throughput fees in our terminals and pipeline operations. For the year ended December 31, 2010, approximately 14% of track transportation revenue was from fees charged to other operations within the Company.
Propane and NGL marketing and distribution
Business Overview
Our propane and NGL marketing and distribution segment includes a retail and wholesale propane business and an NGL marketing business. Our branded Canwest Propane business distributes propane to retail customers throughout western Canada. In the year ended December 31, 2010, Canwest Propane’s retail operations distributed in excess of 68 million gallons to residential and commercial/industrial customers. Over 75% of these volumes were derived from oil and gas related and commercial/industrial volumes, both of which are relatively insulated from weather risk. In addition, we lease the vast majority of our tanks to our customers, providing us with a steady source of cash flow and income and creating a consistent, dependable customer base. Other income includes parts and equipment sales, service labor and rental and delivery charges which are part of the ancillary services performed through our Canwest Propane branch offices.
Over the last 20 years, we have established our presence in the market as the second largest retail propane distributor in Canada. This size enables Canwest Propane to compete for large, geographically diverse accounts that smaller competitors are not able to service. We have established a reputation as a dependable, customer service-oriented propane supplier, consistently honouring our service and supply commitments to our customers and maintaining industry-leading health, safety and environmental standards, as evidenced by our long-standing relationships with leading industry participants. In addition, by operating a wholesale and retail business, we have the purchasing power to enter into large supply contracts at attractive prices. As a result, we are able to offer competitive pricing to our customers. We also offer our customers flexible arrangements such as pre-pay plans based on average estimated annual usage and fixed price plans that smaller competitors do not offer.
Over the last few years, we have grown our presence in the North American wholesale propane distribution market with the acquisition of MP Energy in October 2007 and more recently, with the acquisition of certain propane terminal facilities from Superior Propane LLC and Turner Gas Company in 2009. We now own six propane storage facilities in Ontario, British Columbia, Washington, North Dakota and Montana with combined storage capacity of approximately 1.1 million gallons. Our wholesale propane distribution business sold over 227 million gallons of propane in the year ended December 31, 2010. We also market NGL products in the United States as a result of the NGL marketing business purchased as part of our acquisition of Taylor.
We provide NGL marketing services to our customers in Canada and the U.S. We earn a margin through the purchase and subsequent sale of NGL products such as butane and condensate. We look to take advantage of specific location, quality or time-based arbitrage opportunities when they are available. We market and transport NGL products throughout North America via truck, rail and pipelines. Included in our NGL marketing business is a fractionation plant at our Hardisty Terminal that operates as a processing facility and processes NGL mix and splits it into its components of condensate, butane, propane, ethane and solvents.
Propane sales are categorized according to final usage of the propane at the point of sale. Pricing in both the retail and wholesale markets is heavily dependent on the market pricing of propane, which forms a basis for 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. Wholesale propane and NGL marketing sales are usually in 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 entered into with larger customers. Wholesale fixed price contracts are usually backed with inventory of propane to minimize margin exposure.
Our propane and NGL marketing and distribution segment provided approximately 17%, 12% and 10% of our revenues and 20%, 24% and 19% of segment profit for the years ended December 31, 2010, 2009 and 2008, respectively.
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Customers
Canwest Propane distributes propane to a diverse retail customer base which includes over 34,000 customers across western Canada. In the year ended December 31, 2010, revenue by sector was oil and gas (48%), commercial/industrial (24%), automotive (9%), residential (10%), cylinder (7%) and wholesale (2%). Our top five external customers account for approximately 22% of total retail revenue with no one customer accounting for more than 9% in the year ended December 31, 2010. Typical contract terms are from one to five years with automatic renewal provisions.
We provide wholesale propane distribution to customers in Canada and the U.S. The top five external customers account for approximately 59% of total wholesale propane distribution revenue for the year ended December 31, 2010. We have a long-term fixed margin contract with a major retail propane company in the United States, and in certain instances we are the exclusive supplier for that particular customer for specific geographic regions. This customer, a subsidiary of a publically traded investment grade entity, accounted for 41% of our wholesale propane distribution revenue in the year ended December 31, 2010.
Our customer base for our NGL marketing business is diversified and includes refining customers, independent retailers and other end users. The top five external customers accounted for approximately 28% of total NGL marketing revenue for the year ended December 31, 2010 and other Gibson segments accounted for approximately 26% of NGL marketing revenue.
Competition
In the retail propane marketplace we face competition from large, mid-sized and small players throughout western Canada. Approximately 50 retailers compete for market share across western Canada. The industry is, for the most part, mature with geographic pockets that have higher growth potential (such as oil sands and high drilling activity areas). Our market share and growth potential are based on our ability to provide timely, reliable service at competitive prices to our customers.
Competition is often the greatest in markets such as central Alberta, where supply points are readily available. Smaller retailers are more prevalent in these markets because they are not required to invest capital in storage facilities as they can load directly from the supply source. Price competition also exists among retailers in areas with large oil and gas accounts where significant volumes can be achieved.
Propane also competes with other energy sources, including natural gas, electricity, wood, fuel oil and diesel, many of which are more cost effective on an equivalent energy basis. Propane has advantages over these other fuels in remote locations, in particular where natural gas or electricity is not economically viable.
Competition in the wholesale propane distribution market and NGL marketing business is also strong; however, there are significant barriers to entry, such as high capital requirements. MP Energy has focused on areas that do not have major NGL pipeline infrastructure. Margins there tend to be higher, whereas intense competition occurs in areas where NGL pipelines exist, such as the northeastern U.S. and the mid continental U.S. These assets allow numerous players to share similar economics, which in turn can significantly erode margins. The wholesale business is focused around long-term strategic supply contracts with key players which remove the competition from the picture for the most part. A large part of our business also revolves around strategic terminal assets in areas where competitors who do not have such assets are at a disadvantage.
Integration
Our propane and NGL marketing and distribution segment’s integration with other operating segments provides opportunities to increase overall profitability and cash flow. Our wholesale NGL marketing group is a supplier of condensate and other NGL products to our marketing segment, enabling this segment to capture quality arbitrage opportunities. In the year ended December 31, 2010, approximately 96.1% of the NGL marketing and distribution segment’s truck transportation needs were performed by our truck transportation segment.
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Processing and wellsite fluids
Business Overview
Our processing and wellsite fluids segment utilizes our 16,000 barrel per day refinery, located in Moose Jaw, Saskatchewan, to process heavy crude oil into asphaltic and lighter distillate products. Products include several grades of road asphalt, wellsite fluids, tops and roofing flux. Our refined products are then shipped by truck, rail and pipeline from Saskatchewan to high demand markets in the United States and western Canada. Currently, the refinery processes heavy crude oil received from two independent pipelines and is both interconnected and strategically positioned in close proximity with the critical Enbridge and South Saskatchewan pipelines located between the Canadian oil producing markets and the Canadian and United States product consuming markets. Since we purchased it in 2002, the refinery at Moose Jaw has been upgraded and expanded with further storage facilities and increased rail loading facilities. The refinery processes an average of approximately 12,900 barrels per day of heavy crude oil into an average of approximately 5,600 barrels per day of asphaltic products and approximately 7,300 barrels per day of wellsite fluids or tops. The refinery has approximately 1.0 million barrels of storage capacity, approximately 32 miles of pipelines, truck and rail loading facilities and approximately 682 leased rail cars. We also have a frac fluid reprocessing service business, whereby we recycle used frac fluids and turn the used fluids into a new reusable product.
By processing heavy crude oil, we gain a competitive advantage as some of our competitors process higher-cost light sweet crude and condensate. In addition, we differentiate ourselves from other refineries by producing roofing flux and road asphalt products that are of very high quality and are consistent month-to-month. Most refineries regard asphalt as a by-product of their gasoline production and do not focus on its quality or consistency. Consistency, especially for roofing flux, is very important to our asphalt shingle manufacturing customers. Recently, we have introduced a straight run roofing flux into the market. The advantage of this product is that it can be used directly in the shingle production process without additional blending, saving the shingle manufacturers time and money. Our refinery has a geographic advantage as it is the only refinery in Saskatchewan that focuses on road asphalt. In the year ended December 31, 2010, the refinery was awarded 41% of the road paving jobs tendered by the Government of Saskatchewan. We have also developed a niche market for our wellsite fluid products such as Distillate 822 and Gibson Clear fracturing fluid. It is these products that typically provide the highest margin to us.
Typically, larger road asphalt sales are completed through a market-based tender process, often with the Government of Saskatchewan. The tendering process usually occurs in the spring for paving contracts to be performed in the upcoming summer and fall paving season. The contracts are typically fixed price agreements. Tendered volumes are based on the individual paving projects but delivered volumes are dependent on the ability to complete the paving projects during the season. Roofing flux sales contracts are typically based on variable pricing that is set month-to-month based on crude prices, market demand and other market related factors. Wellsite fluids sales are on a job-by-job basis, with prices based on market prices at the time of sale. The tops product sold by the refinery is typically sold in pipeline batch sizes to our marketing operations for further resale to refineries based on a crude oil based price using the LSB crude stream as a marker.
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, particularly in the United States. 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. Cost of sales, or crude oil costs, for all products depends on availability of feedstock and the landed price for the specific grade of crude oil being processed.
Our processing and wellsite fluids segment provided approximately 9%, 7% and 8% of our revenues and 20%, 18% and 17% of our segment profit for the years ended December 31, 2010, 2009 and 2008, respectively.
Customers
Our customers in the processing and wellsite fluids segment include road construction companies, governments, roofing shingle manufacturers, oilfield drilling contractors, refiners, and oil and gas exploration and production companies. Road asphalt is shipped primarily to customers located in Saskatchewan, the U.S. Northeast, Alberta, Massachusetts, Wisconsin and Iowa and roofing flux is shipped primarily to the U.S. Midwest, U.S. West Coast and U.S. Mid-Atlantic areas. Our top
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five external customers accounted for approximately 24% of segment revenue in the year ended December 31, 2010, with the largest customer accounting for 7%. The two largest customers, to whom we sell roofing asphalt, comprised 13% of our segment revenue.
The significant customers of this segment include Owens Corning, GAF Materials, and Atlas Roofing for roofing flux, the Government of Saskatchewan for road asphalt, and Marquis Alliance, ARC Resources, and Bri-Chem Supply for wellsite fluids.
Competition
Many of our competitors in the processing and wellsite fluids segment are fully integrated national or multinational oil companies engaged in various segments of the petroleum business. However, most refineries produce asphalt as a by-product of their gasoline production and do not focus on quality and consistency. We differentiate ourselves by producing high quality asphalt products and have developed a niche market for our wellsite fluid products.
Integration
By synchronizing with our other business segments, particularly truck transportation and marketing, the processing and wellsite fluids segment enjoys the benefits of having ready access to both heavy crude oil supply and a solid downstream customer base. Approximately 89% of our wellsite fluid truck transportation requirements and approximately 82% of our road asphalt sales are shipped to market by our truck transportation segment.
Marketing
Our marketing segment provides valuable marketing services to our customers and also focuses on increasing volumes through the terminals and pipelines and the truck transportation segments. The marketing segment also takes advantage of specific location, quality or time-based arbitrage opportunities, when they are available. Location-based arbitrages arise when value differentials between crude oil prices at two locations are greater than the transportation cost between the two locations. In these circumstances, we can use our own transportation assets or our access to rail transportation to physically move the product and capture the value differential. Quality-based arbitrage opportunities are dependent on the prevailing price differentials between various grades of crude oil and diluent that can be combined to create a specific crude oil grade. When the combined cost of the components is less than the value of the specific grade created, a positive margin can be earned. At our Hardisty Terminal, we have access to many different crude oil types which enables us to capture quality arbitrage opportunities when they exist. Time-based arbitrage opportunities arise when the forward price curve, typically WTI, is in contango, meaning that forward month’s prices are greater than the current month prices. In this market situation, physical crude oil can be stored using our access to storage and sold forward using financial contracts at prices that are higher than the current physical value of the crude oil. The marketing segment purchases, sells, stores and blends crude oil and condensate, selling an average of approximately 129,000 physical barrels per day in the year ended December 31, 2010, and is responsible for helping to manage our physical commodity positions, based on the needs of each operating segment.
We operate an extensive transportation network that provides a bridge from the wellhead to the refinery gate and allows us to give increased assurance to producers that their production will not get shut-in due to logistical issues between the wellhead and the injection into a main line pipeline system. The extent of the asset network allows us to source more barrels for our marketing segment. Because we are not a production company, we are seen by producers as a business partner, not as a competitor, and have, therefore, developed strong relationships over decades of being in the business of aggregating and marketing physical crude oil.
Our marketing segment provided approximately 65%, 75% and 74% of our revenues and 5%, 8% and 8% of our segment profit for the years ended December 31, 2010, 2009 and 2008, respectively.
Customers
Our marketing segment buys and sells crude oil, condensate and natural gas. The largest component of our revenues is the sale of crude oil. In the crude oil business, our customer base is diversified and includes major integrated oil companies, producers, refineries and an electronic trading platform. Our top five external customers, each investment grade, with the
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exception of Consumers Co-Operative Refineries, which is the subsidiary of an unrated company, accounted for approximately 35% of segment revenue in the year ended December 31, 2010, and other Gibson segments accounted for approximately 18% of segment revenue. The marketing segment’s significant customers include Nexen, Exxon, Cenovus, Tidal and Consumers Co-Operative Refineries.
Competition
Our competitors in the marketing segment include other crude oil pipeline companies, the major integrated oil companies, their marketing affiliates and independent gatherers, investment banks that have established a trading platform, brokers and marketers of widely varying sizes, financial resources and experience.
Competitive Strengths
We believe that we are well-positioned to execute our primary business objectives and strategies because of the following competitive strengths:
· Provider of essential services in the primary hydrocarbon producing regions in Canada and the United States: Our operations are focused on the WCSB, one of the most hydrocarbon rich basins in the world, and key hydrocarbon producing regions throughout the United States. Production growth in these areas should provide opportunities for us to grow our business.
· Valuable footholds in strategic market hubs: Our terminals in Hardisty and Edmonton are at the hub of the energy industry in western Canada, linking producers in the region to the rest of North America. Together, these terminals give our customers access to all the major pipelines moving crude oil to export markets from the WCSB, including connections to the Enbridge, Express, TransMountain, Bow River and Keystone Pipelines, positioning us as the service provider of choice. These footholds not only offer us stable, fee-based cash flow, but also give us insight into the operations and service needs of major participants in the western Canadian energy market, which enhances our ability to meet their changing requirements. These footholds coupled with our long standing industry relationships, serve as a significant barrier to entry, making new entry into the market both time consuming and costly.
· Positioned to capture value throughout the energy value chain: On any given day, a barrel of crude oil that is produced from the wellhead is worth fundamentally less than a barrel delivered to the refinery gate, with the differential in value depending on the quality of the crude produced at the wellhead, the distance and route the barrel needs to travel before it reaches its final destination and the spot price for crude on the open market. Because we provide the gathering, blending, terminalling and transportation services between the wellhead and the ultimate market, we are in a position to capture much of the value differential between the price of a barrel at the wellhead versus at the refinery gate.
· Diversified, integrated, synergistic service offerings: Our integrated range of assets allow us to provide numerous services to our customers. The more services provided, the greater our control of the value chain from the wellhead to the refinery. By integrating our services across business segments, we are able to direct barrels internally, enabling more ‘touches’ on each barrel, and thereby providing more revenue. Access to more barrels also provides the marketing segment with more opportunities to take advantage of quality and location arbitrage conditions. Operated as an integrated network, our assets have provided a diversified and stable stream of cash flows.
· Proven track record of sourcing and successfully executing internal growth projects: We have grown substantially by working with key customers to partner on internal growth projects and also to identify customer needs and initiate projects to meet those needs. For example, we have effectively responded to the growing production coming from the oil sands and have been able to expand our Hardisty Terminal to meet those needs. With approximately 229 acres of undeveloped land in Hardisty and Edmonton, we are well positioned to meet future expansion opportunities as they arise. As well, our Canwest Propane and truck transportation operations have grown in step with increasing production volumes from conventional and unconventional production.
· Proven track record of sourcing, executing and successfully integrating business acquisitions: We have demonstrated an ability to identify and execute accretive acquisitions.
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During the three years ended December 31, 2010, we completed a total of eight business acquisitions for total consideration of approximately $266.1 million. Given consolidation opportunities, especially in the truck transportation and propane and NGL marketing and distribution segments, we expect that acquisitions will continue to be an important source of growth.
· Leading health, safety, security and environmental record: Throughout our long history, we have continually focused on having “best in class” operations with respect to health, safety, security and environmental compliance. We have been recognized by the Province of Alberta for excellence in these areas, which we believe gives us a competitive advantage versus competitors lacking either the knowledge or the resources to match our performance. Several of our customers are large, multinational oil companies that have very strict guidelines on the standards to which their service providers must adhere. Our record on health, safety, security and environmental matters allows us to do business with the most discriminating market participants.
· Experienced management with a proven history of profitable operations and strong industry reputation: Our senior management team members have an average of 27 years of industry experience. In addition, our Chief Executive Officer and Chief Financial Officer have each worked for the Company for approximately 20 years. Our management team has demonstrated a long track record of consistently and conservatively growing our business and producing strong returns on assets and equity. Our senior management team is well recognized in the industry and has developed a reputation for integrity, innovation and customer service.
· High quality, energy-focused investor: Riverstone is an energy focused private equity firm with approximately U.S.$17.0 billion of assets under management and deep knowledge and experience in the midstream sector. Riverstone has a long track record of successful investments in the energy sector, and has developed a high level of expertise in areas such as capital raising and acquisitions. Past Riverstone investments include Kinder Morgan, Buckeye Partners L.P. and Magellan Midstream Partners, L.P., amongst others.
Environmental
We recognize and value the importance of responsible environmental stewardship and have made significant investments in infrastructure to improve efficiencies and enhance environmental performance. Our environmental programs focus on preventing adverse environmental impact and adopting appropriate remediation strategies when required. We are committed to conducting our business in a way that balances diverse stakeholder expectations, respects the environment and protects the health and safety of our employees and communities. As part of this commitment, we strive to conduct our operations in accordance with all applicable legislation and regulation along with our internally developed environmental operating guidelines and provide our employees with comprehensive training that emphasizes health, safety, security and environmental matters.
Our operations are subject to various environmental laws and regulations that establish compliance and remediation obligations. We utilize a risk-based approach to environmental management. Business unit and/or facility inspections are completed regularly, depending on the assessment of risk. We comply with the requirements of all applicable federal, provincial, state and municipal health, safety and environmental laws and regulations in the communities where we operate, and we have a well-established reporting program to ensure potential hazards, which may impact workers or the public, are proactively mitigated. Incident investigations are performed to determine root causes and findings are shared with all our facilities.
Health, safety, security and environmental training is provided to all employees to ensure that they can perform their work in a manner reflective of our values. Our corporate and field emergency response plans meet all federal, provincial and state regulations and are properly maintained.
We regularly review security alert messages from internal and external agencies and update employees with the information. We have a strict security protocol for plant visitors and restricted plant access to all facilities.
We hold a current Alberta Health & Safety Certificate of Recognition. Key performance indicators and targets are reviewed by our Health, Safety, Security & Environment Executive Steering committee, and our policies and procedures are
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continuously monitored and updated to ensure regulatory compliance and to reflect technical developments and improved industry standards related to our facilities.
We maintain insurance of various types with varying levels of coverage that we consider adequate to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable. Consistent with insurance coverage generally available in the industry, our insurance policies in certain circumstances provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.
We endeavour to be a leader in pipeline and system integrity by:
· implementing rigorous inspection and preventative maintenance programs;
· pursuing technology advances;
· participating in industry forums to share and exchange knowledge; and
· supporting provincial excavation one-call efforts to reduce the risk of third-party damage to pipelines.
Leak prevention and small-piping-integrity initiatives and changes to engineering standards have all contributed to reductions in reportable leaks at our pipeline facilities. Our strong focus on advancing pipeline integrity is aimed at technological advances as well as understanding the science of how to find, mitigate and prevent leaks or ruptures on the pipeline systems.
There are no outstanding orders, material claims or lawsuits against us in relation to the release or discharge of any material into the environment or in connection with environmental protection. We believe we have established appropriate reserves, where required, for environmental liabilities.
Legal Proceedings
We are from time to time a party to legal proceedings which arise in the normal course of business. We are not currently involved in any material litigation, the outcome of which would, in management’s judgment based on information currently available, have a material adverse effect on our financial condition, results of operations or cash flows.
Regulation
The oil, natural gas, NGL and propane industries are subject to extensive controls and regulations imposed by various levels of government. In Canada, the various provincial governments have legislation and regulations that govern environmental protection, the prevention of waste, waste management and other matters. We do not believe that any of these controls and regulations affect our operations in a manner materially different than they would affect other midstream companies of similar size. The controls and regulations should be considered carefully by investors in the oil, natural gas, NGL and propane industries. Set out below is a discussion of some of the principal aspects of certain legislation and regulations governing the oil, natural gas, NGL and propane industries, including a summary of certain laws and regulations that directly affect our business. You should not rely on such discussion as an exhaustive review of all regulatory considerations affecting these industries or our business. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted.
General Environmental Legislation
The oil, natural gas, NGL and propane industries in Canada are currently subject to environmental regulation, including federal and provincial legislation and municipal by-laws. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil, natural gas, NGL and propane operations. Compliance with such legislation can require significant expenditures. A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations and civil liability for pollution damage.
Federal. The Fisheries Act (the “FA”) and its regulations and the Canadian Environmental Protection Act, 1999 (the “CEPA”) are the federal government’s environmental legislation of general application throughout Canada. The FA prohibits the harmful alteration, disruption or destruction of fish habitat or the deposit of a deleterious substance in waters frequented
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by fish, except in accordance with regulations or authorizations issued by the Ministry of Fisheries and Oceans Canada. Punishments for an indictable offence of these provisions include a fine of up to $1.0 million for a first offense, and any subsequent offense includes a fine of up to $1.0 million or imprisonment for a term not exceeding three years, or both.
The CEPA and its regulations apply to several industrial activities in Canada, including the management of certain toxic and other harmful substances (e.g. polychlorinated biphenyls) and the manufacture and importation of substances new to Canada. The federal Minister of the Environment exercises powers under the CEPA to require companies with large facilities to report publicly their annual releases of certain substances of concern through the National Pollutant Release Inventory program and prepare environmental emergency plans if operations at a company’s facility handle certain substances in sufficient quantities. The CEPA also regulates environmental matters affecting certain interprovincial activities (e.g. manifesting shipments of hazardous waste between provinces) and international activities (e.g. export of hazardous waste and hazardous recyclable materials from Canada). Punishments for an indictable offence of these provisions include a fine up to $1.0 million for each offense, or imprisonment for a term not exceeding three years, or both.
Alberta. The primary environmental legislation of general application in Alberta is the Environmental Protection and Enhancement Act, 2000 (the “EPEA”) and its regulations. Under the EPEA, environmental standards and compliance obligations for releases, clean up and reporting are subject to scrutiny by Alberta’s Ministry of Environment (“Alberta Environment”) and the public. Liability for clean up, remediation and reclamation costs may be imposed on a wide range of parties, including present and past owners or occupants of contaminated sites or those that had charge, management or control of a substance that has been spilled or released. In addition, Alberta Environment may issue environmental protection orders against any such parties requiring the cleanup of contamination resulting from historic or current operations. Regulators may issue shut down orders where facilities or pipelines are not in compliance with the environmental laws or operating approvals. Fines under the EPEA for non-compliance by companies may be as high as $1.0 million for each day or part day that an offense under the EPEA continues. Individuals who commit offenses under the EPEA may be subject to fines, imprisonment, or both.
The Energy Resources Conservation Board (the “ERCB”) has jurisdiction over environmental matters under Alberta’s Oil and Gas Conservation Act, Pipeline Act and other legislation. The ERCB has also issued multiple information letters, directives and guides with strict obligations and standards concerning matters such as oilfield waste management, spill reporting and the suspension, abandonment and reclamation of oil and natural gas facilities that must be factored into the cost of conducting operations in Alberta.
The legislation in Alberta also allows the ERCB, Alberta Environment and Alberta Occupational Health and Safety to inspect and investigate and, where a practice employed or a facility used is hazardous to human health or the environment, to make remedial orders.
British Columbia. The primary environmental legislation of general application in British Columbia is the Environmental Management Act, 2003 (the “EMA”) and its regulations. The EMA regulates, among other things, the discharge of waste, the management of hazardous wastes and the remediation of contaminated sites. Hazardous wastes must be confined, stored and disposed of in accordance with the EMA. The EMA also imposes liability for remediation costs in respect of a contaminated site on a wide range of parties, including current and previous owners and operators of the site. In British Columbia, the B.C. Oil and Gas Commission regulates oil and gas activity and the Ministry of Environment has jurisdiction over environmental matters under the EMA.
The penalties for failing to comply with the hazardous waste requirements and waste discharge requirements in the EMA include a fine of up to $1.0 million for each day that the failure continues additional fines, imprisonment, suspension or cancellation of a permit or approval, and a Cabinet order restraining an activity or operation.
Saskatchewan. The Environmental Management and Protection Act, 2002 (the “EMPA”) and its regulations is the environmental protection legislation of general application in Saskatchewan. Amongst other things, the EMPA prescribes requirements for permits relating to the protection of water, including aquatic habitat protection permits and industrial effluent works permits. The EMPA also prohibits, unless otherwise authorized, discharges of substances that cause, or may cause, an adverse effect to the environment, which is defined under the EMPA to include ecological and climatic relationships in the environment. In relation to such discharges, Saskatchewan’s Environment Minister has powers under the
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EMPA not only to issue clean-up orders, but also to designate an area as a contaminated site, to provide notification to all persons connected to the contaminated site, and to enforce remedial action plans against any person responsible for the discharge. Anyone who discharges, or allows, an unauthorized release into the environment must report this to Saskatchewan’s Environment Ministry, as well as other affected parties, and take all reasonable measures to remedy the release. The EMPA provides that parties have the right to seek civil compensation for unauthorized releases and other environmental harms, whether or not the person responsible has been convicted of an offense. In addition, a contravention of the EMPA or its regulations is punishable by a fine of up to $1.0 million or imprisonment not exceeding three years, or both.
Other environmental legislation also applies to our operations in Saskatchewan, including the Clean Air Act, 2003 (the “CAA”) and its regulations which mandates that permits must be sought for the operation of any fuel-burning or industrial source of emissions or incinerators. The CAA also prohibits discharges in excess of permitted amounts or which exceed limits of certain air pollutants outlined in an appendix. Failure to comply with a permit, the CAA or its regulations is punishable by a fine of up to $1.0 million, by imprisonment, or both.
United States. The propane industry in the United States is subject to federal, state and local requirements, which are primarily safety-oriented. Under the USEPA regulations implementing the Clean Air Act of 1990 (“USCAA”) Section 112(r), propane handling and storage facilities are required to develop a risk management program to prevent accidental chemical releases. Transportation of propane in pipelines or motor carriers is regulated by the United States Department of Transportation. Worker safety at propane facilities is regulated by the United States Occupational Safety and Health Administration. State and local jurisdictions may impose additional requirements on propane storage and distribution operations; often this involves incorporation by reference of the standards of non-governmental organizations such as the National Fire Protection Association. Under the USCAA and the National Energy Policy Act of 1992, propane is an approved, alternative clean fuel.
Climate Change
Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other GHG. The Canadian federal government has announced its intention to regulate air pollution and GHG emissions by establishing mandatory emissions. The Canadian federal government previously released the Regulatory Framework for Air Emissions, updated March 10, 2008 by Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions (collectively, the “Regulatory Framework”), for GHG emissions by proposing mandatory emissions intensity reduction obligations on a sector by sector basis. Legislation to implement the Regulatory Framework had been expected to be put in place this year, but the federal government has delayed the release of any such legislation and potential federal requirements in respect of GHG emissions are unclear. On January 30, 2010, the Canadian federal government announced its new target to reduce overall Canadian GHG emissions by 17% below 2005 levels by 2020, from the previous target of 20% from 2006 levels by 2020, to align itself with U.S. policy. In 2009, the Canadian federal government announced its commitment to work with the provincial governments to implement a North American-wide cap and trade system for GHG emissions, in cooperation with the United States. Canada would have its own cap-and-trade market for Canadian-specific industrial sectors that could be integrated into a North American market for carbon permits.
As the details of the implementation of any federal legislation for GHGs have not been announced, the effect on our operations cannot be determined at this time.
In Alberta, regulations governing GHG emissions from large industrial facilities came into effect on July 1, 2007. The regulations apply to all facilities in Alberta that have produced 100,000 or more tonnes of CO2e in 2003 or any subsequent year. The regulations require subject facilities to achieve yearly reductions in GHG emissions intensity (i.e. the quantity of GHG emissions per unit of production). Generally, the emissions intensity target is a 12% reduction in emissions intensity as compared with the baseline for the facility (as established in December 31, 2007 for existing facilities or the third year of commercial operations for new facilities). For facilities with less than 8 years of commercial operations, targets are phased in at 2% increments beginning in the fourth year of commercial operation (i.e. newer facilities will have a 2% reduction in emissions intensity as their target during their fourth year of commercial operations, a 4% reduction during their fifth year, and so forth until the recurrence of the annual 12% reduction requirement). Under the regulations, there are three ways to meet emissions intensity reduction targets: (i) improve operational efficiency in terms of GHG emissions, with excess
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improvements generating emission performance credits that are both bankable and tradeable; (ii) purchase verified, Alberta-based emission offset credits and/or emission performance credits; or (iii) purchase “fund credits” at a cost of $15 per excess tonne of CO2e emissions, with the proceeds going into Alberta’s Climate Change and Emissions Management Fund run by the Alberta Government.
None of our Alberta facilities produce emissions above the threshold of 100,000 tonnes of CO2e annually. We do not expect ongoing compliance costs associated with these regulations at our facilities will have a material adverse effect on our operations or financial condition. The Alberta Government announced in January 2008 a new climate change plan setting out a goal of achieving a 14% absolute reduction in GHG emissions below 2005 levels in the province by 2050. Additionally, the Alberta Government has also indicated that the current GHG emission regime may change, which changes will likely include more onerous emission intensity reduction obligations and limits on the availability of funds credits or the cost of those credits. These announcements may result in further regulatory requirements that could affect our business, but any such requirements are currently unknown.
In May, 2010, the Management and Reduction of Greenhouse Gases Act (the “MRGGA”) received Royal Assent in the Province of Saskatchewan. However the MRGAA is still awaiting proclamation and is currently undergoing a consultative process. The new legislation would establish a provincial plan for reducing GHG emissions to meet provincial targets and promote investments in low-carbon technologies. Saskatchewan has indicated that it intends to enter into an equivalency agreement with the federal government to achieve equivalent outcomes under provincial regulation. A draft of the proposed regulations calls for a reduction of emissions by 20% below 2006 levels. Regulated emitters will consist of those which produce at least 50,000 tonnes of CO2e in any year. Regulated emitters will be required to reduce emissions by 2% per year from 2010 to 2019 in order to meet the 20% target reduction by 2020. In the year ended December 31, 2010, none of our Saskatchewan facilities produced emissions above the threshold of 50,000 tonnes of CO2e annually.
The Canadian federal government proposes to enter into equivalency agreements with provinces that establish comparable regulatory regimes to ensure consistency with federal plans, but the success of any such agreement is uncertain in the current political climate, leaving the potential for multiple levels of regulation regarding GHG emissions. The direct and indirect costs of these regulations may adversely affect our operations and financial condition.
The U.S. Energy Independence and Security Act of 2007 precludes agencies of the U.S. federal government from procuring motor fuels from non-conventional petroleum sources that have lifecycle GHG emissions greater than equivalent conventional fuel. This may have implications for our marketing in the United States of some heavy oil and oil sands production, but the impact on our business cannot be determined at this time.
The U.S. Congress is actively considering cap and trade and other legislation to regulate emissions of GHGs on an economy-wide basis, including from mobile (e.g., cars, trucks and engines) and stationary sources, fuel producers and importers. In addition, a number of U.S. states and some Canadian provinces have formed regional partnerships to regulate GHG emissions. The USEPA recently promulgated a mandatory GHG emission reporting program that requires nearly all sectors of the U.S. economy, including upstream producers and suppliers of fossil fuels or industrial GHGs, manufacturers of vehicles and engines, and downstream facilities, to report their GHG emissions. The USEPA also recently responded to the U.S. Supreme Court’s April 2007 ruling in Massachusetts v. USEPA with a finding that six GHGs fall under the federal USCAA’s definition of “air pollutant” and endanger public health and welfare, and GHG emission from new mobile sources contribute to GHGs in the atmosphere. This finding is the predicate to regulation of new on-road mobile sources under the USCAA by the USEPA. USEPA is continuing to evaluate, and will address in later actions, pending petitions that request the USEPA to regulate GHGs emissions from other mobile sources (e.g., airplanes and ships), fuels and stationary sources under certain USCAA programs. Regulation of GHG emission by the USEPA and through regional partnerships may occur even if Congress does not adopt new legislation specifically addressing GHG emission. New legislation or regulatory programs that restrict GHG emission in areas where we conduct business could adversely affect our operations and demand for our services.
Other Emissions
Owners of hydrocarbon storage and processing facilities in Canada are subject to regulatory requirements that impose emissions limits on their facilities. If it is determined that emissions exceed such permitted limits, owners of such facilities may be subject to fines, orders or revocations of permits, licenses and authorizations. Compliance with emissions limits may
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require substantial investment or an extension to allow a facility to continue to emit at current levels. There are no assurances that such extensions would be granted. It is expected that any proposed federal GHG emissions legislation will also impose limits on certain other air pollutants as well.
On October 2, 2007, the Alberta Government announced a new cumulative effects initiative covering a 470-square-kilometer area northeast of Edmonton known as the Alberta Industrial Heartland (“AIH”). This initiative establishes regional targets for air, water and land quality. All large industrial facilities within the AIH will be subject to a cumulative airshed target of 25,000 tonnes per year of nitrous oxide and 28,000 tonnes per year of sulfur dioxide. In addition, restrictions on individual water use within the AIH are being implemented pursuant to Alberta’s Water Act, and land use restrictions may be imposed under the Alberta Land Stewardship Act.
Currently, we have no facilities located in the AIH. Based on the information currently available, we do not anticipate that this initiative will require significant changes to our current operations. However, the effect that the cumulative effects initiative in the AIH may have on future operations or possible expansion is not clear at this time.
Particulate Matter and Ozone Management Framework
Alberta Environment, together with the non-profit multi-stakeholder partnership Clean Air Strategic Alliance, has implemented the Particulate Matter and Ozone Management Framework (the “Framework”) to ensure Canada-wide standard levels of particulate matter and ozone (established in 2000 by the Canadian Council of Ministers of the Environment) are not exceeded in Alberta after 2010. Where monitoring shows that Canada-wide standard levels are being approached in a given region of Alberta, then the Framework requires the establishment of a regional management plan to control particulate matter and ozone. Few, if any, of our operations generate material amounts of particulate matter. The only material source of ozone from our operations is as a byproduct of emissions from combustion processes. Aside from the emissions from diesel truck operations, the only other significant combustion processes involve the heaters at our Hardisty fractionation plant, which may be affected by implementation of the Framework should a management plan be developed for the Hardisty area.
In addition, certain of our operations must comply with ERCB requirements for fugitive emissions management programs set out under Directive 060, Upstream Petroleum Industry Flaring, Incineration and Venting.
Legislative and Regulatory Changes Regarding Royalties
On October 25, 2007, the Alberta Government released the “New Royalty Framework,” which took effect on January 1, 2009, and which modified the manner in which royalties will be charged on oil and gas producing properties in Alberta. This and other measures having the effect of increasing royalties could adversely affect drilling activity in Alberta in future years. The New Royalty Framework was modified on March 3, 2009 when the Alberta Government announced a three-point incentive program. These two programs expired on March 31, 2011.
Effective January 1, 2011, the Alberta Government adjusted royalty rates including making the incentive program royalty rate of 5% on new natural gas and conventional oil wells a permanent feature of the royalty system with current time and volume limits. The maximum royalty rate will be 40% for conventional oil and 36% for natural gas. All royalty curves were finalized and announced on May 31, 2010. The implementation of the royalty adjustments is subject to certain risks and uncertainties, including changes to existing legislation and the regulation and development of proprietary software to support the calculation and collection of royalties.
Changes to royalty rates do not directly impact us as we have no oil and gas production. However, such changes may indirectly impact our results should the producers and shippers operating in areas serviced by us decide to take actions, such as reduced capital programs or curtailment of volumes shipped, as a result of increased royalties.
Gibson’s Operations
Our operations, involving the transportation, storage, blending, processing and distribution of crude oil, condensate, NGLs, LPGs, refined products and natural gas, are subject to federal, provincial and state laws and regulations that govern the
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discharge of materials into the environment or that otherwise relate to the protection of the environment. Compliance with these laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. Failure to comply with these laws and regulations could result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, and even the issuance of injunctions that may subject us to additional operational requirements and constraints. Environmental and safety laws and regulations are subject to change resulting in more stringent requirements, and we cannot provide any assurance that compliance with current and future laws and regulations will not have a material effect on our results of operations or earnings. A discharge of a substance into the environment could, to the extent such an event is not insured, subject us to substantial expense, including both the cost to comply with applicable laws and regulations and any claims made by neighboring landowners and other third parties for personal injury and natural resource and property damage.
The following is a summary of some of the environmental and safety laws and regulations to which our operations are subject.
Pipeline safety and integrity management. Regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. We must operate our pipelines in accordance with various government and regulatory standards. Our pipelines are tested on a periodic basis and are subject to inspection by the ERCB, among other bodies. Although we believe that our pipeline operations are in substantial compliance with currently applicable regulatory requirements, we cannot predict the potential costs associated with additional, future regulation.
Storage facilities safety. In Canada, various federal and provincial agencies have jurisdiction to regulate the construction, alteration, inspection, repair, and abandonment of crude oil storage tanks, including the ERCB and Alberta Environment in Alberta, and the Ministry of the Environment in Saskatchewan.
In Alberta, we operate a storage tank monitoring, upgrade and replacement program in compliance with the regulatory requirements of ERCB Directive 55, Storage Requirements for the Upstream Petroleum Industry. We spent approximately $2.6 million for the year ended December 31, 2010, $2.0 million in 2009, $3.6 million in 2008, $4.1 million in 2007, and $1.9 million in 2006 on pipeline and storage tank compliance activities in Alberta. Our estimate for 2011 is that we will need to spend approximately $2.1 million to be in compliance.
In Saskatchewan, our storage tanks are managed to meet the requirements of the Government of Saskatchewan’s Hazardous Substances and Waste Dangerous Goods Regulations. These requirements include standards for the design and construction of new storage tanks and inspection, maintenance and repair of existing storage tanks. We spent approximately $1.7 million in the year ended December 31, 2010, $1.1 million in 2009, $1.3 million in 2008, $1.5 million in 2007 and $3.1 million in 2006 on storage tank compliance activities in Saskatchewan. Our estimate for 2011 is that we will need to spend approximately $1.5 million to remain in compliance.
We expect to continue to incur costs under laws and regulations related to storage tank and pipeline integrity, such as operator competency programs, regulatory upgrades to our operating and maintenance systems and environmental upgrades of buried sump tanks. Certain of these costs are recurring in nature and thus will affect future periods. We will continue to refine our estimates as information from our assessments is collected.
Transportation regulation. Our transportation activities are subject to several transportation regulations in connection with our truck transportation segment. Our historic and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues.
Our truck transportation assets are subject to regulation by both federal, provincial and state transportation agencies in the provinces and states in which we operate. These regulatory agencies do not set freight rates, but do establish and administer rules and regulations relating to other matters including equipment, facility inspection, reporting, environmental compliance and safety.
Water. Canadian and U.S laws impose restrictions and strict controls regarding the discharge of pollutants into the jurisdictional waters of Canada and the United States, as well as provincial and state waters. Permits or approvals must be
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obtained to discharge pollutants into these waters. A permit is also required for the discharge of dredge and fill material into regulated waters, including wetlands. All provinces and states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with any such applicable provincial and state requirements. Under these laws, regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of applicable laws and regulations. Although we can give no assurances, we believe that compliance with existing permits and compliance with foreseeable new permit or approval requirements will not have a material adverse effect on our financial condition or results of our operations.
Releases of substances into the environment. Canadian and U.S. laws impose liability for releases of hazardous substances, including oil, and for releases of substances into the environment that cause or may cause an adverse effect. Statutory liability for clean-up and remediation of such releases can be imposed on a wide range of persons, including the owner or former owner of the substance or facility, or any person that had charge, management or control of the substance. Moreover, in the United States, strict, joint and several liability can be imposed on such persons for costs required to clean up and restore sites where releases of hazardous substances have occurred. Release of a hazardous substance or a substance that causes or may cause an adverse effect may also give rise to civil claims against a person responsible for the release. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by substances or other pollutants released into the environment.
Occupational health and safety. Regulatory requirements exist in Canada and the United States under federal, provincial, state and local occupational health and safety legislation and related codes. The agencies with jurisdiction under these regulations are empowered to enforce them through inspection, audit, incident investigation or public or employee complaint. Additionally, under Canadian and U.S. criminal law, organizations, corporations and individuals may be prosecuted criminally for violating the duty to protect employee and public safety. We believe that our operations are in substantial compliance with applicable occupational health and safety requirements.
We comply with the requirements of all applicable federal, provincial, state and municipal health, safety and environmental laws and regulations in the communities where we operate, and we have a well-established reporting program to ensure potential hazards, which may impact workers or the public, are proactively mitigated. Incident investigations are performed to determine root causes and findings are shared with all Gibson-operated facilities.
Health, safety, security and environmental training are provided to all employees to ensure that they can perform their work in a manner reflective of our values. Our corporate and field emergency response plans meet all federal, provincial and state regulations and are properly maintained.
We regularly review security alert messages from internal and external agencies and update employees with the information. We have a strict security protocol for plant visitors and restricted plant access for all facilities.
We hold a current Alberta Health & Safety Certificate of Recognition. Key performance indicators and targets are reviewed by our Health, Safety, Security & Environment Executive Steering committee, and our policies and procedures are continuously monitored and updated to ensure regulatory compliance and to reflect technical developments and improved industry standards related to our operations.
Environmental remediation. We maintain insurance of various types with varying levels of coverage that we consider adequate to cover our operations and properties. The insurance policies are subject to deductibles and retention levels that we consider reasonable. Consistent with insurance coverage generally available in the industry, our insurance policies in certain circumstances provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences.
Our refinery operations at Moose Jaw operate pursuant to a December 2001 Environmental Management Agreement with the Minister of Saskatchewan Environment and Resource Management (now known as the Saskatchewan Ministry of the Environment) which requires us to remediate historic on-site contamination for a period of ten years from 2001 at an aggregate cost of $3.5 million. As partial consideration for this expenditure, the Saskatchewan government has agreed not to take any action against us for on-site historic contamination at the Moose Jaw refinery. The Saskatchewan Ministry of the
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Environment has advised that it is satisfied with our remediation work to date. If we own the refinery at Moose Jaw beyond the expiry of the ten-year remediation period, we are required under the Environmental Management Agreement to spend up to an additional $1.5 million to remediate any remaining on-site historic contamination.
We have entered into indemnification agreements with various counterparties in conjunction with the occupation of various sites used in our propane and marketing distribution and truck transportation segments, and also in connection with the divestiture of two gas plants to Altagas Services Inc. in 2003. These contractual indemnifications are typically subject to specific monetary requirements that must be satisfied before indemnification will apply and have term and total dollar limits. Allocation of environmental liability is an issue negotiated in connection with each of our acquisition transactions. In each case, we make an assessment of potential environmental exposure based on available information. Based on that assessment and relevant economic and risk factors, we determine whether to negotiate an indemnity, what the terms of any indemnity should be (for example, minimum thresholds or caps on exposure) and whether to obtain environmental risk insurance, if available.
Asset acquisitions are an integral part of our business strategy. As we acquire additional assets, we may be exposed to environmental remediation liabilities for which we are not indemnified and we may be required to incur additional costs in order to ensure that the acquired assets comply with the regulatory standards in Canada and the United States.
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4.C. ORGANIZATION STRUCTURE
Gibson Energy Holding ULC is the ultimate parent of Gibson Energy ULC. The following list includes all subsidiaries of Gibson Energy ULC as at December 31, 2010 and indicates their respective jurisdictions of incorporation. All of the voting securities of each significant subsidiary are held directly or indirectly by Gibson Energy ULC. All subsidiaries are 100% owned unless otherwise stated.
GEP Midstream Finance Corp. (Alberta, Canada)
Moose Jaw Refinery ULC (Alberta, Canada)
Moose Jaw Refinery Partnership (Alberta, Canada)
Canwest Propane ULC (Alberta, Canada)
Canwest Propane Partnership (Alberta, Canada)
MP Energy ULC (Alberta, Canada)
MP Energy Partnership (Alberta, Canada)
GEP ULC (Alberta, Canada)
Gibson Energy Partnership (Alberta, Canada)
Link Petroleum Services Ltd. (British Columbia, Canada)
Link Petroleum, Inc. (Washington, USA)
Gibson Energy (U.S.) Inc. (Delaware, USA)
Southern Valley Energy, LLC (North Dakota, USA) (50%)
Gibson GCC Inc. (Alberta, Canada)
Bridge Creek Trucking Ltd. (Saskatchewan, Canada)
Johnstone Tank Trucking Ltd. (Saskatchewan, Canada)
Chief Hauling Contractors ULC (Alberta, Canada)
Gibson Finance Ltd. (Alberta, Canada)
Gibson (U.S.) Holdco Corp. (Delaware, USA)
Gibson (U.S.) Acquisitionco Corp. (Delaware, USA)
Gibson (U.S.) Finco Corp. (Delaware, USA)
Taylor Companies, LLC (Delaware, USA)
TPG Transport, LLC (Delaware, USA)
TPG Leasing, LLC (Delaware, USA)
Taylor Transfer Services, LLC (Texas, USA)
Taylor Gas Liquids, LLC (Texas, USA)
Taylor Land Holdings, LLC (Montana, USA)
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4.D. PROPERTY, PLANTS AND EQUIPMENT
Our headquarters are located in approximately 162,408 square feet of office space in Calgary, Alberta, Canada under a lease that expires in 2020, of which we are currently subleasing 40,532 square feet to third parties. We also lease land and office space through Gibson Energy ULC and its various subsidiaries. The table below describes each of our materially important physical properties.
Facility location | | Approx. size | | Owned/
leased | | Description |
| | | | | | |
Corporate | | | | | | |
| | | | | | |
1700, 440 2nd Avenue SW
Calgary, AB | | 162,408 sq. ft. | | Leased | | Head office |
| | | | | | |
3819 Towne Crossing Blvd, Mesquite, TX, U.S. | | 19,020 sq. ft. | | Leased | | U.S. head office |
| | | | | | |
Terminals and pipelines | | | | | | |
| | | | | | |
10534 17th Avenue
Edmonton, AB *
(Edmonton South Terminal) | | 82 acres | | Owned | | Crude terminal with shipping, receiving and blending facilities (including rail loading/unloading) |
| | | | | | |
Hardisty, AB * | | 363 acres
(comprising
six parcels) | | Owned | | Crude oil shipping, receiving & blending terminal and frac plant |
| | | | | | |
Hays, AB | | 3 acres | | Leased | | Crude oil terminal |
| | | | | | |
Morinville, AB | | 2 acres | | Leased | | Crude oil terminal |
| | | | | | |
Niton Terminal, AB | | 7 acres | | Leased | | Crude oil terminal |
| | | | | | |
5512 40 Street
Rimbey, AB | | 11 acres | | Owned | | Crude oil terminal |
| | | | | | |
County of Wheatland, AB | | 5 acres | | Leased | | Hussar crude oil terminal |
| | | | | | |
Municipal District of Yellowhead
No. 94, AB | | 3 acres | | Owned | | Edson crude oil terminal |
| | | | | | |
Fryburg, Bellfield, ND, U.S. | | 2 acres | | Leased | | Injection station |
| | | | | | |
Liberty, MS, U.S. | | 2 acres | | Leased | | Injection station |
| | | | | | |
Labourge, Fayette, TX, U.S. | | 3 acres | | Leased | | Injection station |
| | | | | | |
Eunice, LA, U.S. | | 5 acres | | Leased | | Injection station |
| | | | | | |
Truck transportation and propane and NGL marketing and distribution | | | | | | |
| | | | | | |
1785, 1791, 1767 Eagle Rock Road
Armstrong, BC | | 2 acres | | Owned | | Offices and propane storage facility |
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3023, 3083 49 Avenue SE
Calgary, AB | | 2 acres | | Owned | | Trailer parking, shop, offices |
| | | | | | |
5205 76th Avenue SE
Calgary, AB | | 2 acres | | Owned | | Storage yard, shop, offices, propane storage facility |
| | | | | | |
5654 55 Street SE
Calgary, AB | | 6 acres | | Leased | | Offices and shops |
| | | | | | |
323 116 Avenue NW
Edmonton, AB | | 2 acres | | Leased | | Offices and shops |
| | | | | | |
7524 49 Street
Edmonton, AB | | 0.4 acres | | Leased | | Office, shop and propane storage yard |
| | | | | | |
Ernestown, ON | | 6 acres | | Owned | | Office, propane storage facility |
| | | | | | |
8208 Manning Avenue
Fort McMurray, AB | | 0.3 acres | | Owned | | Office, propane storage facility |
| | | | | | |
235 MacAlpine Crescent
Fort McMurray, AB | | 0.1 acres | | Leased | | Office and shop, propane storage facility |
| | | | | | |
140 MacLennan Crescent
Fort McMurray, AB | | 2 acres | | Leased | | Office and shop, propane facility |
| | | | | | |
101—1st Street
Frobisher, SK | | 3 acres | | Owned | | Office and shop |
| | | | | | |
#1 Railway Avenue
Frobisher, SK | | 1 acre | | Owned | | Office and shop |
| | | | | | |
Grand Prairie, AB | | 9 acres | | Owned | | Office and shop |
| | | | | | |
Grand Prairie, AB | | 21 acres | | Owned | | Bare land |
| | | | | | |
Gull Lake | | 3 acres | | Owned | | Crude oil terminal |
| | | | | | |
6663 Queens Avenue
Gull Lake, SK | | 0.6 acres | | Leased | | Shop |
| | | | | | |
6664 Queens Avenue
Gull Lake, SK | | 0.3 acres | | Leased | | Office |
| | | | | | |
#10 and #20 Industrial Avenue
Gull Lake, SK | | 1 acre | | Leased | | Shop |
| | | | | | |
4603, 4607, 4611, 4615 and 4315 49th Street
Hardisty, AB | | 3 acres | | Owned | | Office and shop |
| | | | | | |
Lot 11, Industrial Road #1
Invermere, BC | | 1 acre | | Leased | | Office, propane storage facility |
| | | | | | |
5503 63rd Avenue
Lloydminster, AB * | | 5 acres | | Owned | | Office and shop, propane storage facility |
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Municipal District of Opportunity
No. 17, AB | | 0.3 acres | | Owned | | Shop and propane storage facility |
| | | | | | |
North Dakota, U.S. | | 2 acres | | Leased | | Propane storage facility, rail loading/unloading |
| | | | | | |
940 Church Road
Parksville, BC | | 0.6 acres | | Leased | | Propane storage facility and service shop |
| | | | | | |
Peace River, AB | | 2 acres | | Leased | | Office, propane storage facility |
| | | | | | |
Hart Hwy
Prince George, BC | | 2 acres | | Leased | | Propane storage facility and service shop |
| | | | | | |
7905 50 Avenue
Red Deer, AB | | 1 acre | | Leased | | Office, shop and propane storage facility |
| | | | | | |
425 7th Avenue W.
Shaunavon, SK | | 4 acres | | Leased | | Shop, truck, propane storage facility |
| | | | | | |
1006 Mclean-Macpherson Rd.
Sicamous, BC | | 2 acres | | Owned | | Gas bar and convenience store, offices, propane storage facility |
| | | | | | |
23733 116th Ave.
Surrey, BC * | | 3 acres | | Owned | | Office and shop, propane storage facility |
| | | | | | |
1440 Port of Tacoma Rd
Tacoma, Washington, U.S. | | 3 acres | | Leased | | Office, propane storage facility |
| | | | | | |
Town of Valleyview, AB | | 4 acres | | Owned | | Propane storage facility |
| | | | | | |
Wabasca, AB | | 7 acres | | Owned | | Camp parking, propane storage facility |
| | | | | | |
1702 15th Avenue
Municipal District of
Wainwright, AB | | 1 acre | | Owned | | Office, shop and propane storage |
| | | | | | |
Processing and wellsite fluids | | | | | | |
| | | | | | |
Moose Jaw, SK * | | 101 acres | | Owned | | Refinery for several grades of road asphalt, wellsite fluids, tops and roofing flux |
* A fixed charge over each of these properties has been obtained for the benefit of the holders of the First Lien Notes.
On November 30, 2010, we entered into a business relationship with Suncor Energy Inc. to build and operate four 300,000 barrel tanks at our Hardisty Terminal. The four tanks are to be built as a standalone facility which will provide Suncor with the ability to grow its business and manage the quality of its proprietary commodity streams. The tanks will be located near and connected to all major pipelines that connect to our main Hardisty Terminal. The total cost of construction is estimated to be approximately $88.0 million, with our share being 50% of the total and is expected to be completed by the fourth quarter of 2012. As of December 31, 2010, we have spent $2.7 million of our share on the project.
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Item 4A. Unresolved Staff Comments
None
Item 5. Operating and Financial Review and Prospects
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following information should be read in conjunction with our audited consolidated financial statements and related notes for the year ended December 31, 2010, for the year ended December 31, 2009, for the period from December 13, 2008 to December 31, 2008, and for the period from January 1, 2008 to December 12, 2008, 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 25 to our audited consolidated financial statements.
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 for the year ended December 31, 2008 on a combined basis in addition to the separate Predecessor and Successor periods. Combined financial information for the year ended December 31, 2008 represents the aggregation of the period from January 1, 2008 until December 12, 2008 and the period from December 13, 2008 until December 31, 2008 and includes the effects of purchase accounting and the related financing from the date of Acquisition. 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. All references to years, unless otherwise noted, refer to our fiscal years, which end on December 31. 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 Item 3.D.”Risk factors” and “Disclosure regarding forward-looking information” included elsewhere in this Form 20-F. Our actual results may differ materially from those contained in or implied by any forward-looking statements.
EXECUTIVE OVERVIEW
We are one of the largest independent midstream energy companies in Canada and a major participant in the crude oil transportation business in the United States and are engaged in the movement, storage, blending, processing, marketing, and distribution of crude oil, condensate, natural gas liquids, and refined products. We transport hydrocarbons by utilizing our integrated network of terminals, pipelines, storage tanks, and truck fleet located throughout western Canada and the United States. We are also involved in the processing, blending and marketing of hydrocarbons and are the second largest retail propane distribution company in Canada. Our integrated operations allow us to participate across the full midstream energy value chain, from the hydrocarbon producing regions in Canada and the United States, through our strategically located terminals in Hardisty and Edmonton, Alberta and injection stations in the United States, to the refineries of North America via major pipelines.
We have provided market access to leading oil and gas participants in western Canada for the last 58 years. We have grown our business by diversifying our service offerings to meet customers’ needs and by expanding geographically. Most recently, we expanded our service offerings to key hydrocarbon producing regions throughout the United States to position us as a North American midstream energy company.
Our five integrated business segments can be broken down as follows: (1) terminals and pipelines, (2) truck transportation, (3) propane and NGL marketing and distribution, (4) processing and wellsite fluids and (5) marketing. We believe our
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competitive advantage is driven by our geographic presence in some of the most hydrocarbon-rich basins in the world, our footholds in strategic market hubs, our positioning which enables us to capture value throughout the energy value chain , our diversified, integrated, synergistic service offerings, our proven track record of sourcing and successfully executing internal growth projects, our proven track record of sourcing, executing and successfully integrating business acquisitions, our leading health, safety, security and environmental record, our experienced management with a proven history of profitable operations and strong industry reputation and our high quality, energy-focused investor. We are continuously focused on improving our operations across all segments by lowering costs, utilizing our integrated asset base to capture inter-segment 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 2010, we re-evaluated how we internally manage our business as we realigned the operations of our NGL marketing business and the operations of our fractionation 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 year ended December 31, 2010 were:
· On May 14, 2010, we completed the acquisition of Taylor for approximately $153.2 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 key hydrocarbon producing regions throughout the United States. This acquisition expanded our presence as a leading North American midstream company;
· On August 25, 2010, we completed the acquisition of the remaining 75% equity interest in BRT for approximately $54.8 million. 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;
· On November 30, 2010, we entered into a business relationship with Suncor Energy Inc. to build and operate four 300,000 barrel tanks at our Hardisty Terminal (“Hardisty West Terminal”). The four tanks are to be built as a standalone facility which will provide Suncor with the ability to grow its business and manage the quality of its proprietary commodity streams. The Hardisty West Terminal will be located near and connected to all major pipelines that connect to our main Hardisty Terminal. The total cost of construction is estimated to be approximately $88.0 million, with our share being 50% of the total;
· On January 31, 2010, we completed the acquisition of Johnstone Tank Trucking Ltd. (“Johnstone”) for approximately $21.3 million, expanding our truck transportation market presence, particularly in the Bakken production area. On February 1, 2010, we also completed the acquisition of Aarcam Propane & Construction Heat Ltd. (“Aarcam”), a propane business located in Calgary, Alberta, for approximately $3.4 million;
· On January 19, 2010, we issued 10.0% Senior Notes due 2018 in an aggregate principal amount of U.S.$200.0 million. In addition, we also entered into amendments to our Credit facility to increase the total borrowing capacity for revolving loans and letters of credit in an aggregate principal amount of up to U.S.$200.0 million;
· Revenue increased 6% and cost of sales increased 7% in the year ended December 31, 2010 compared to the year ended December 31, 2009, primarily due to global commodity price increases and an increase in truck transportation revenue as a result of the Taylor and Johnstone acquisitions;
· In the year ended December 31, 2010 total segment profit increased 6% compared to the year ended December 31, 2009, as a result of increases in the truck transportation and processing and wellsite fluids segments offset by declines in our other operating segments;
· Net income was $0.2 million in the year ended December 31, 2010 compared to net loss of $62.9 million in the year ended December 31, 2009. The decrease in the net loss was primarily due to the absence of any impairment of goodwill and intangible assets in the year ended December 31, 2010 compared to an impairment of $114.1 million in the year
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ended December 31, 2009. This was offset by lower foreign exchange gains and increased interest expense in the year ended December 31, 2010 compared to the year ended December 31, 2009;
· We participated in a private placement financing with Palko, a waste management provider, for approximately $3.1 million that allowed us to maintain our approximate 39% equity interest and to provide financing to Palko to complete its acquisition of the remaining interest in Palko Energy Ltd., further expanding its interests in the Bakken area of Southeast Saskatchewan. Palko provides hydrocarbon waste management and resource recovery solutions to the upstream and midstream oil and gas industry in western Canada; and
· Employee headcount increased by 130 people, or 14%, in the year ended December 31, 2010 compared to a decrease by 16 people, or 2% in the year ended December 31, 2009. The increase in the year ended December 31, 2010 was largely driven by the additional headcount from the Taylor acquisition.
On January 7, 2011, we completed the disposition of our Edmonton North Terminal to Pembina Midstream Limited Partnership for approximately $54.3 million. The terminal was a remotely operated facility located in Edmonton, Alberta, with a capacity of 310,000 barrels, which had been in exclusive use by our marketing segment. In order to facilitate the growth of the Edmonton South Terminal, as part of the consideration received, we secured important pipeline assets and future connections that will provide access to crude oil streams within the Edmonton area.
On April 27, 2011, our affiliate Gibson Energy Inc. filed a preliminary prospectus with the securities regulatory authority in each of the provinces and territories of Canada, whereby it intends to complete an initial public offering of its common shares (the “Offering”). Concurrent with the Offering, we intend to enter into a series of transactions intended to refinance our existing indebtedness (the “Refinancing”). As part of the transactions, Gibson Energy Holding ULC, Gibson Energy Inc. and 1441682 Alberta Ltd. will amalgamate into one entity, with the surviving entity being Gibson Energy Inc. (the “Reorganization”). The Reorganization is a common control transaction whereby Gibson Energy Inc. will be accounted for using continuity of interest and, as such, Gibson Energy Inc. will be considered a continuity of Gibson Energy Holding ULC. We intend to use the proceeds from the Offering and the Refinancing to offer to purchase for cash any and all of our outstanding First Lien Notes and Senior Notes and to repay any amounts outstanding under the Credit facility.
The key highlights of the year ended December 31, 2009 were:
· We commissioned the Battle River Terminal at Hardisty, Alberta with a storage capacity of 1.2 million barrels for a total cost of approximately $72.0 million;
· We completed the acquisition of Bridge Creek Trucking Ltd. (“Bridge Creek”) for approximately $6.9 million, expanding our market presence in the southwest area of Saskatchewan. We also completed the acquisition of the wholesale propane business and assets of the Washington and Oregon operations of Turner Gas Company (“Turner”) for $1.6 million and we completed the acquisition of certain propane terminal facilities and the associated businesses in Montana and South Dakota from Superior Propane LLC for approximately $6.7 million;
· We acquired an equity interest of approximately 39% in Palko for total consideration of $6.6 million;
· On May 27, 2009, we issued 11.75% First Lien Senior Secured Notes due 2014 in an aggregate principal amount of U.S.$560.0 million, the proceeds of which were used to repay our U.S.$230.0 million first lien senior secured interim credit agreement and the U.S.$315.0 million second lien senior secured interim credit agreement (together, the “Bridge Loans”) in full. In connection with the repayment, we recorded debt extinguishment costs of $18.5 million. In addition, we realized a foreign exchange gain of $61.4 million on the repayment of the Bridge Loans;
· Revenue declined 28% and cost of sales declined 29%, primarily due to global commodity price declines;
· Despite a global recession, the terminals and pipelines and the propane and NGL marketing and distribution segments showed increases in segment profits. However, total segment profit declined by 5%, due primarily to the decline in our truck transportation segment profit;
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· Net loss was $62.9 million for the year ended December 31, 2009 compared to net income of $66.3 million for the year ended December 31, 2008. The decrease was primarily due to increases in our interest expense and depreciation and amortization expense as a result of the Acquisition, and an impairment charge relating to goodwill and intangible assets. These were offset by foreign exchange gains on our long-term debt;
· Following the retirement of our previous President and Chief Executive Officer, we promoted a new President and Chief Executive Officer; and
· Employee headcount remained relatively stable, decreasing by 16 people or 2% in the year ended December 31, 2009, compared to an increase of 116 people or 15% during the year ended December 31, 2008.
Trends affecting our business
In accordance with our long-range strategic plan, we are continuously evaluating organic growth opportunities and potential acquisitions of transportation, retail propane distribution, gathering, terminalling or storage and other complementary midstream businesses. In 2010, 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, and the acquisition of the remaining interests of BRT, which was comprised of storage tanks connected to our Hardisty Terminal. Some of the key industry trends that are currently affecting our business and prospects are:
· Increased activity levels are forecasted to continue in the Bakken, Cardium, Viking, Eagle Ford, and Niobrara areas stemming from increased drilling budgets proposed by industry leaders. We believe this should generate increased demand for the services we provide;
· The unrest in the Middle East that is currently occurring is underscoring the importance of domestic oil production to the North American market. We believe this should result in an increased focus on development of North American supply and regenerate drilling activity and production levels domestically;
· Technology advancements within the drilling and fracturing process are providing production companies new opportunities to increase production levels from wells that were previously uneconomic and to bring on production from areas that were previously unable to economically produce crude oil, such as tight shale plays;
· Increased production levels and increased crude oil prices have increased demand for all facets of the midstream energy value chain including storage, transportation, distribution, processing and refining, all of which are activities in which we participate; and
· In late 2009 and for the first nine months of 2010, heavy to light crude oil pricing differentials were at historically low levels. During the latter part of 2010, there has been a widening of these differentials more in line with longer term averages. This creates incremental margin opportunities in multiple areas of our operations.
Longer-term outlook
Our longer-term outlook, spanning three to five years or more, is influenced by many factors affecting the North American midstream energy sector. Some of the more significant trends and developments relating to crude oil include:
· New technology and drilling methodology being deployed towards conventional and unconventional production within our operating areas;
· Uncertainty and volatility relating to crude oil prices and price differentials between crude oil streams and blending agents;
· Increased crude oil production on shore in North America, including from the Canadian oil sands; and
· Expansion of the midstream infrastructure in North America to handle increased production and expansion of capacity in the U.S. refining complex to handle heavier crude oil from the WCSB.
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We believe the collective impact of these trends and developments, many of which are beyond our control, will result in an increasingly volatile crude oil market that is subject to more frequent short-term swings in market prices and grade differentials and shifts in market structure.
Acquisitions and internal growth projects
We completed a number of acquisitions and capital expansion projects in the years ended December 31, 2010, 2009 and 2008. The following table summarizes our capital expenditures for internal growth projects, acquisitions and upgrade and replacement capital (in thousands):
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008(2) | |
Internal growth projects | | $ | 30,635 | | $ | 15,784 | | $ | 28,677 | |
Acquisitions, including equity investments | | 235,796 | | 21,808 | | 18,180 | |
Upgrade and replacement capital(1) | | 31,047 | | 21,183 | | 17,977 | |
| | $ | 297,478 | | $ | 58,775 | | $ | 64,834 | |
(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.
(2) Capital expenditures above do not include amounts related to the Acquisition.
Internal growth projects
In the year ended December 31, 2010, our internal growth projects included: the continued expansion of our Canwest Propane truck fleet and tankage; building new tanks at the Edmonton South and Hardisty Terminals; the expansion of our truck transportation fleet and the expansion of capacity and construction of a new tank at the Moose Jaw Refinery.
In the year ended December 31, 2009, our internal growth projects included: the completion of a new frac fluid recycling facility, which incorporates technology acquired from the acquisition of REV Fluid Solutions Inc.; the continued expansion of our truck transportation fleet; expansion of our Canwest Propane truck fleet and tankage; building a new tank at the Edmonton South Terminal, expansion of capacity and building of a new tank at the Moose Jaw Refinery, and the completion of the Battle River Terminal at Hardisty, Alberta.
In the year ended December 31, 2008, our internal growth projects included: the purchase of land and the ongoing construction of a new frac fluid recycling facility; the expansion of blending facilities at our Hussar and Edmonton North terminals; the continued expansion of our truck transportation fleet; and the ongoing construction of the Battle River Terminal at Hardisty, Alberta.
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The following table summarizes our key projects undertaken in the years ended December 31, 2010, 2009 and 2008 (in thousands):
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
Canwest Propane fleet and tank expansion(1) | | $ | 4,540 | | $ | 4,417 | | $ | 3,519 | |
Edmonton South Terminal storage tank construction(2) | | 1,697 | | 1,422 | | — | |
Moose Jaw refinery capacity expansion(3) | | 4,433 | | 3,237 | | — | |
Purchase of land(4) | | 1,601 | | 1,080 | | — | |
Truck transportation trailer fleet expansion(5) | | 4,735 | | 924 | | 3,427 | |
Rail loading rack at Edmonton(6) | | 2,576 | | — | | — | |
Hardisty storage tank construction(7) | | 3,136 | | — | | — | |
Hardisty West Terminal project(8) | | 2,713 | | — | | — | |
Hardisty line 4 (MM150) connection(9) | | 364 | | — | | — | |
Hardisty Cold Lake pipeline connection(10) | | 476 | | — | | — | |
Southern Lights connection at Edmonton(11) | | 545 | | — | | — | |
Frac fluid recycling facility(12) | | — | | 1,922 | | 5,978 | |
Blending facilities(13) | | — | | 11 | | 4,467 | |
Building expansions at Moose Jaw and Lloydminster(14) | | — | | 97 | | 2,443 | |
Other growth projects(15) | | 3,819 | | 2,674 | | 8,843 | |
Total | | $ | 30,635 | | $ | 15,784 | | $ | 28,677 | |
(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 December 31, 2010 was $3.1 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, in the year ended December 31, 2010 and in Sicamous, British Columbia in the year ended December 31, 2009, both 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 build a tank at out Hardisty Terminal. We have entered into an agreement whereby, on completion, the tank will be leased to a customer on a long-term minimum fee basis.
(8) Represents capital spent to date in connection with the Hardisty West Terminal project. The total cost of construction is estimated to be approximately $88.0 million, with our share being 50% of the total.
(9) Represents capital spent to build a connection from Enbridge line 4 at our Hardisty Terminal. The total cost of the construction is estimated to be $9.5 million.
(10) Represents capital spent to build a connection to the Cold Lake pipeline system at our Hardisty Terminal. The total cost of the construction is estimated to be $5.4 million.
(11) Represents capital spent to connect the Edmonton South Terminal to the Southern Lights pipeline. The total cost of the construction is estimated to be $6.6 million.
(12) 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 $7.9 million.
(13) Represents capital spent to add facilities to enable butane blending into crude oil streams at our Hussar and Edmonton North terminals.
(14) Represents an office building expansion at the Moose Jaw Refinery and an office building and trailer shop expansion at Lloydminster for our propane and NGL marketing and distribution and truck transportation segments, respectively.
(15) Represents a number of smaller projects similar in nature to, but smaller in scope than, those discussed above.
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Acquisitions
In the year ended December 31, 2010, we completed a number of acquisitions, including the acquisition of Taylor for aggregate consideration of $153.2 million, effective May 14, 2010; the acquisition of the remaining 75% equity interest of BRT that we did not already own for aggregate consideration of $54.8 million, effective August 25, 2010; the acquisition of Johnstone for aggregate consideration of $21.3 million, effective January 31, 2010; and the acquisition of 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 $3.1 million, thereby allowing us to maintain our approximately 39% equity interest.
In the year ended December 31, 2009, we completed the acquisition of Bridge Creek for aggregate consideration of $6.9 million, effective May 1, 2009; the acquisition of the wholesale propane business and assets of the Washington and Oregon operations of Turner for $1.6 million, effective July 1, 2009; and the acquisition of certain propane terminal facilities and the associated businesses in Montana and South Dakota from Superior Propane LLC for $6.7 million, effective November 18, 2009. In addition we acquired an approximate 39% equity interest in Palko, a waste management provider, for $6.6 million.
In the year ended December 31, 2008 we completed the acquisition of Chief Hauling Contractors Inc. (“Chief”) for aggregate consideration of $14.4 million and made a $3.8 million equity investment in BRT.
The acquired businesses impacted our results of operations commencing on the effective date of each acquisition as indicated in the table below.
The following table summarizes the acquisitions and equity investments that were completed in the years ended December 31, 2010, 2009 and 2008 (in thousands):
Acquisition | | Effective date | | Acquisition price | | Operating segment | |
Battle River Terminal ULC(1) | | June 18, 2008 | | $ | 3,750 | | Marketing and terminals and pipelines | |
Chief Hauling Contractors Inc. | | June 1, 2008 | | 14,430 | | Truck transportation | |
Bridge Creek Trucking Ltd | | May 1, 2009 | | 6,900 | | Truck transportation | |
Turner Gas Company | | July 1, 2009 | | 1,608 | | Propane and NGL marketing and distribution | |
Superior Propane | | November 18, 2009 | | 6,657 | | Propane and NGL marketing and distribution | |
Palko Environmental Ltd.(2) | | December 15, 2009 | | 6,643 | | Terminals and pipelines | |
Johnstone Tank Trucking Ltd. | | January 31, 2010 | | 21,266 | | Truck transportation | |
Aarcam Propane & Construction Heat Ltd. | | February 1, 2010 | | 3,437 | | Propane and NGL marketing and distribution | |
Taylor Companies LLC | | May 14, 2010 | | 153,194 | | Truck transportation, terminals and pipelines and propane and NGL marketing and distribution | |
Palko Environmental Ltd. (3) | | June 30, 2010 | | 3,050 | | Terminals and pipelines | |
Battle River Terminal ULC(4) | | August 25, 2010 | | 54,849 | | Terminals and pipelines | |
Total | | | | $ | 275,784 | | | |
(1) Represents a 25% equity investment in BRT, not included as a business acquisition in the accompanying financial statements.
(2) Represents an approximate 39% equity investment in Palko, not included as a business acquisition in the accompanying financial statements.
(3) Represents our participation in a private placement in Palko, thereby allowing us to maintain our approximately 39% equity interest.
(4) Represents the remaining 75% equity interests in BRT.
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Seasonality
We believe that seasonality does not have a material impact on our combined operations and segments. However, certain of our individual segments are impacted by seasonality. Generally, our results are impacted in the second quarter due to road bans and other restrictions which impact overall activity levels in the WCSB, and therefore negatively impacting our trucking and wellsite fluids business in Canada.
Our processing and wellsite fluids segment is impacted by seasonality because the asphalt industry in Canada is affected by the impact that weather conditions have on road construction schedules. Refineries produce liquid asphalt year round, but asphalt demand peaks during the summer months when most of the road construction activity in Canada takes place. Demand for wellsite fluids is dependent on overall well drilling activity, with drilling activity normally the busiest in the winter months. As a result, our processing and wellsite fluids segment’s sales of liquid asphalt peak in the summer and sales of wellsite fluids peak in the winter.
Our propane and NGL marketing and distribution segment is characterized by a high degree of seasonality with much of the seasonality driven by the impact of weather on the need for heating and the amount of propane required to produce power for oil and gas related applications. Therefore, volumes are low during the summer months relative to the winter months. Operating profits are also considerably lower during the summer months. Most of the annual segment profits are earned from October to March each year.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The consolidated financial statements have been prepared in accordance with Canadian GAAP. Our significant accounting policies are more fully described in note 1 to our audited consolidated financial statements. In applying these critical accounting policies, our management uses its judgment to determine the appropriate assumptions to be used in making certain estimates. Estimates are used in the assessment of the recoverability of accounts receivable, the carrying value of goodwill and intangible assets, future income taxes, asset retirement obligations, valuation of stock options, valuation of pension assets, liabilities and related expenses, the determination of certain future obligations and the purchase price allocation in connection with acquisitions. In addition, estimates related to the useful life of property, plant and equipment and intangible assets are required in order to calculate depreciation and amortization. Actual results may differ from estimated amounts as future confirming events occur.
The accounting estimates and assumptions discussed in this section are those that involve significant judgment and the most uncertainty. Changes in these estimates or assumptions could materially affect our financial position and results of operations and are therefore important to an understanding of our consolidated financial statements. We believe the following critical accounting policies reflect our more significant estimates and the assumptions used in the preparation of our consolidated financial statements.
Financial instruments. In situations where we are required to mark the derivatives to market, the estimates of gains or losses at a particular period-end do not reflect the end results of particular transactions, and will most likely not reflect the actual gain or loss at the conclusion of the underlying transactions. We reflect the fair value estimates for derivative instruments based on valuation information from third parties. The calculation of the fair value of certain of these derivatives is based on proprietary models and assumptions of third parties because such instruments are not quoted on an active market. Additionally, estimates of fair value for such derivative instruments may vary among different models due to a difference in assumptions applied, such as the estimate of prevailing market prices, volatility, correlations and other factors, and may not be reflective of the price at which they can be settled due to the lack of a liquid market. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, the actual amounts may vary significantly from estimated amounts.
Preferred shares. Preferred shares issued by Gibson Energy Holding ULC in connection with the Acquisition will be converted to Class B common shares at September 1, 2011, except to the extent that they are redeemed in whole or in part prior to that date. The preferred shares are contingently redeemable upon the qualified initial public offering of Gibson Energy Holding ULC of more than U.S.$100 million in net proceeds and have liquidation preferences as compared to other classes of common stock of the Company. The preferred shares are entitled to mandatory cumulative dividends at an
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annual rate of 12% of the accreted value of the preferred shares until December 12, 2010. From December 13, 2010 to September 1, 2011, the annual rate increases to 13% of the accreted value of the preferred shares. At any time prior to September 1, 2011, the Company can elect to redeem the preferred shares for a cash payment equal to the issue price per share, plus all unpaid dividends that have accrued. We recognize accrued dividends for each period as a reduction of our retained earnings and an increase in the carrying value of the preferred shares. Under U.S. GAAP such preferred shares are classified as mezzanine financing outside of shareholders equity, which results in an accounting difference between Canadian and U.S. GAAP. See notes 23 and 25 to our audited consolidated financial statements for additional details of accounting for the preferred shares.
Accruals and contingent liabilities. We use estimates to record accruals or liabilities for environmental remediation and governmental penalties, insurance claims, asset retirement obligations, taxes, potential legal claims, and other accruals and liabilities. Accruals are made when our assessment indicates that it is probable that a liability has occurred and the amount of liability can be reasonably estimated. Our estimates are based on all known facts at the time and our assessment of the ultimate outcome. Among the many uncertainties that impact our estimates are the necessary regulatory approvals for, and potential modification of, our environmental remediation plans, the limited amount of data available upon initial assessment of the impact of soil or water contamination, changes in costs associated with environmental remediation services and equipment, costs of medical care associated with worker’s compensation and employee health insurance claims, and the possibility of existing legal claims giving rise to additional claims. Our estimates for contingent liability accruals are increased or decreased as additional information is obtained or resolution is achieved. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, actual amounts may vary significantly from estimated amounts.
Fair value of assets and liabilities acquired and identification of associated goodwill and intangible assets. In conjunction with each acquisition, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. We also estimate the amount of transaction costs that will be incurred in connection with each acquisition. As additional information becomes available, we may adjust our original estimates subsequent to the acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Goodwill and intangible assets with indefinite lives are not amortized but instead are periodically assessed for impairment. We do not have any recorded intangible assets with an indefinite life outside of goodwill. The impairment testing entails estimating future net cash flows relating to the asset, based on management’s estimate of market conditions including pricing, demand, competition, operating expenses and other factors. Intangible assets with finite lives are amortized over the estimated useful life determined by management. Determining the fair value of assets and liabilities acquired, as well as intangible assets that relate to such items as customer relationships, brands, contracts, and industry expertise involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets acquired and, to the extent available, third party assessments. Uncertainties associated with these estimates include changes in production decline rates, production interruptions, fluctuations in refinery capacity or product slates, economic obsolescence factors in the area and potential future sources of cash flow. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, the actual amounts may vary significantly from estimated amounts. We perform our goodwill impairment test annually (as of November 30) and when events or changes in circumstances indicate that the carrying value may not be recoverable. We did not have any impairment charges in the year ended December 31, 2010. In the year ended December 31, 2009, we recorded an impairment of $85.5 million relating to goodwill in our truck transportation segment. The impairment loss was determined by calculating the fair value of the truck transportation reporting unit based on values of comparable businesses and comparing it to the reporting unit’s book value. In addition, we also recorded an impairment of $28.6 million to intangible assets in our truck transportation segment, relating to customer relationships and brands. We used an income approach to determine the fair value of customer relationships and a royalty savings approach to determine the fair value of brands. We did not have any impairment charges in the year ended December 31, 2008.
Defined benefit pension plans and post-retirement benefits accruals. The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management’s best estimates of demographic and financial assumptions, and such cost is accrued proportionately from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based on a year-end market rate of interest for high-quality debt instruments with cash flows that match the timing and amount of expected benefit payments. Uncertainties involved in the estimate of the expenses related to the defined benefit pension plan and post-retirement benefits include the discount rate used to present value the obligations under the plans, the expected long-term rate of return on the plan’s assets, the rate of compensation increase and the assumed health care trend
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rate. Although the resolution of these uncertainties has not historically had a material impact on our results of operations or financial condition, actual amounts may vary significantly from estimated amounts in future periods.
Property, plant and equipment and depreciation expense. We compute depreciation using the straight-line method based on estimated useful lives. We periodically evaluate property, plant and equipment for impairment when events or circumstances indicate that the carrying value of these assets may not be recoverable. The evaluation is highly dependent on the underlying assumptions of related cash flows. We consider the fair value estimate used to calculate impairment of property, plant and equipment a critical accounting estimate. In determining the existence of an impairment in carrying value, we make a number of subjective assumptions as to the grouping of assets, the intention of “holding” versus “selling” an asset, the forecast of undiscounted expected future cash flow over the asset’s estimated useful life, whether there is an indication of impairment, and if an impairment exists, the fair value of the asset or asset group. Impairments were not material for the years ended December 31, 2010, 2009 and 2008.
Stock based compensation. We estimate the grant-date fair value of stock options using a Black-Scholes valuation model. Our calculation of stock based compensation requires us to make a number of complex and subjective estimates and assumptions, including the fair value of our common stock, forfeitures, volatility and expected life of the options. The options have a graded vesting schedule and each vesting portion is amortized separately over the requisite service period with a corresponding credit to contributed surplus. Upon exercise, the associated amount is reclassified from contributed surplus to share capital. Consideration received from plan members upon exercise of options is credited to share capital.
Changes in Accounting Policies
The Company adopted the following new accounting policies in the year ended December 31, 2010:
Capital Leases
Contractual arrangements that transfer substantially all the risks and benefits of ownership of property to the lessee and, at the inception of the lease, the fair value of the leased property is equal to the Company’s carrying amount of the property are recorded as a net investment in a capital lease. The minimum lease payments under such arrangements are recorded at the inception of the agreement and the finance income is recognized in a manner that produces a consistent rate of return on the investment in the capital lease and is included in revenue.
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 IFRS effective January 1, 2011. The changeover date is for interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. We will convert to these new standards, which will mean that the first set of financial statements to be prepared under IFRS will be for the three months ended March 31, 2011, with comparative IFRS information for the three months ended March 31, 2010.
We have made significant progress on the changeover plan. We are currently finalizing our IFRS accounting policies and have actively worked to select, when appropriate, consistent accounting policies in an effort to preserve comparability. We remain focused on the transition to IFRS and have prepared preliminary financial statements under IFRS for the year ended December 31, 2010 to provide for comparative financial statements after the official changeover in 2011. 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 established for the significant areas of impact, including processes to capture the required 2010 IFRS comparative data. IFRS education and training sessions have been held internally and these sessions will continue in 2011 as needed.
We believe that the significant areas of impact are summarized below. However, our IFRS financial results have not yet been finalized because:
· The results remain subject to further review by management;
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· Management is continuing to monitor any new or amended IFRS issued by the International Accounting Standards Board that could affect our choice of accounting policies;
· Our IFRS financial statements must use the standards that are in effect on December 31, 2011, and therefore our IFRS accounting policies will only be finalized when our first annual IFRS financial statements are prepared for the year ending December 31, 2011; and
· The results are unaudited and are subject to additional audit work by our external auditors.
Impairment testing. Under IFRS, the recoverable amount used in recognizing and measuring an impairment is the greater of the asset’s fair value less costs to sell and its value in use. Under Canadian GAAP, the recoverable amount used to determine whether recognition of an impairment loss is required is the undiscounted future cash flows expected from its use and eventual disposition. As a result of the change in approach, on January 1, 2010, we will recognize an impairment charge of $40.1 million relating to property, plant and equipment and of $9.6 million relating to intangible assets. As a result of this impairment charge, depreciation and amortization expense is expected to decrease by $5.8 million for the year ended December 31, 2010.
Asset retirement obligations. On transition to IFRS, we elected to remeasure asset retirement obligations in accordance with the provisions of IAS 37 “Provisions, Contingent Liabilities and Contingent Assets”. Under IFRS, the liability is remeasured at each reporting date using the current risk free interest rate as opposed to the credit adjusted rate used under Canadian GAAP. As a result, on January 1, 2010, we increased property, plant and equipment by $12.8 million and the asset retirement obligations liability by $19.3 million, with a net impact to retained earnings of $6.5 million. In addition, as a result of acquisitions during the year, we remeasured our asset retirement obligations on the acquisition dates, which resulted in an additional increase in property, plant and equipment and asset retirement obligations liability of $1.9 million. As a result, the expense relating to the unwinding of the discount increased by $0.8 million for the year ended December 31, 2010 and depreciation of property, plant and equipment increased by $0.3 million for the year ended December 31, 2010.
Capitalized Interest. Under Canadian GAAP, capitalization of interest during the construction of a qualifying asset was an acceptable, but not mandatory, accounting policy. We chose not to capitalize interest for qualifying assets. Under IFRS, capitalization of interest is required for qualifying assets under construction prior to the time they are ready for use. As a result, on January 1, 2010, the carrying value of property, plant and equipment was increased by $0.3 million. In addition, under IFRS, interest capitalized was $1.2 million during the year ended December 31, 2010 As a result, depreciation of property, plant and equipment increased by $0.1 million for the year ended December 31, 2010.
Employee benefit plans. Under IFRS, we elected to recognize actuarial gains and losses arising from the re-measurement of employee future benefit obligations in other comprehensive income as they arise. Under Canadian GAAP, we applied the corridor method of accounting whereby gains and losses are recognized only if they exceed specified thresholds. Accordingly, under IFRS, the carrying value of the net liability for employee future benefit obligations will increase by approximately $2.8 million to recognize actuarial losses accumulated on the transition date of January 1, 2010. In addition, at December 31, 2010, we recognized an additional $0.6 million to the carrying value of the net liability for employee future benefit obligations. As a result, amortization of the unrecognized loss under Canadian GAAP is no longer required, resulting in a decrease in general and administrative expense of $0.2 million in the year ended December 31, 2010.
Capitalized software. Under Canadian GAAP, capitalized computer software was included within property, plant and equipment. Under IFRS, capitalized computer software, not integral to plant and equipment, is classified as an intangible asset. On January 1, 2010, we reclassified approximately $4.6 million from property, plant and equipment to intangible assets. In the year ended December 31, 2010, we incurred approximately $2.0 million of capitalized computer software, which was reclassified from property, plant and equipment to intangible assets. There was no net impact in the statement of income.
Business Combinations. Under Canadian GAAP, the purchase price of an acquisition includes direct costs incurred by the acquirer, such as finder’s fees, advisors, legal, accounting, valuation and other professional or consulting fees. Under IFRS, these costs associated with business acquisitions are expensed in the period they are incurred. We elected to apply IFRS to all business combinations that occurred on or after January 1, 2010. The impact was additional general and administrative expense of $2.6 million in the year ended December 31, 2010 and a corresponding decrease in goodwill of $2.6 million.
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Property, plant and equipment. Under IFRS, we are required to identify material components of assets within property, plant and equipment, and depreciate the components based on the estimated service life of the components. Under Canadian GAAP, we had recognized certain components in prepaid expenses and other assets. On January 1, 2010, we reclassified $3.1 million from short term and long-term prepaid expenses and other assets to property, plant and equipment. In the year ended December 31, 2010, we reclassified $1.3 million from short term and long-term prepaid expenses and other assets to property, plant and equipment. As a result of the reclassifications, there was no net impact in the statement of income.
Revenue. Under Canadian GAAP, we classified certain realized and unrealized gains (losses) on financial instruments in revenue. Under IFRS, these financial instruments do not meet the revenue recognition criteria. The impact was to reclassify $12.5 million of losses from revenue to cost of sales in the year ended December 31, 2010. There was no net impact in the statement of income.
Income taxes. We have evaluated the differences in guidance between International Accounting Standard 12, “Income Taxes” and the relevant Canadian GAAP requirements and concluded that, other than the tax effecting the adjustments, the impact will be minimal. In addition, under Canadian GAAP, deferred income tax relating to current assets or current liabilities were classified as current. Under IFRS, it is not appropriate to classify deferred income tax balances as current, irrespective of the classification of the assets or liabilities to which the deferred income tax relates to or the expected timing of reversal. Accordingly, current deferred income tax reported under Canadian GAAP will be reclassified as non-current under IFRS.
As a result of the transition adjustments identified above, the following table is a preliminary summary of the expected unaudited historical financial information under IFRS compared to Canadian GAAP as of December 31, 2010 and January 1, 2010 and for the year ended December 31, 2010:
| | As of December 31, 2010 | | As of January 1, 2010 | |
| | IFRS | | Canadian GAAP | | IFRS | | Canadian
GAAP | |
| | (in thousands) | |
| | | | | | | | | |
Cash and cash equivalents | | $ | 7,225 | | $ | 7,225 | | $ | 26,263 | | $ | 26,263 | |
Property, plant and equipment | | 629,755 | | 652,885 | | 570,307 | | 598,826 | |
Intangible assets | | 152,339 | | 129,726 | | 121,909 | | 126,955 | |
Total assets | | 1,992,382 | | 2,022,765 | | 1,637,278 | | 1,673,894 | |
Long-term debt | | 718,154 | | 718,154 | | 553,942 | | 553,942 | |
Total liabilities | | 1,447,574 | | 1,436,104 | | 1,092,700 | | 1,085,250 | |
Shareholder’s equity | | 544,808 | | 586,661 | | 544,578 | | 588,644 | |
| | | | | | | | | | | | | |
| | Year ended December 31, 2010 | |
| | IFRS | | Canadian GAAP | |
| | (in thousands) | |
Revenue | | $ | 3,690,452 | | $ | 3,677,988 | |
Depreciation and amortization | | 89,890 | | 94,145 | |
Interest expense | | 99,736 | | 99,451 | |
Loss before income taxes | | (9,473 | ) | (13,191 | ) |
Net income | | 2,943 | | 155 | |
| | | | | | | |
In general, the impact of IFRS largely relates to the accounting for non-cash items. Therefore, we expect that the adoption of IFRS will have a minor impact on our operations or strategic decisions. We believe that most of our key performance measures such as segment profit, EBITDA and Pro Forma Adjusted EBITDA, which is used in calculating our covenant compliance, will not be materially impacted by the transition to IFRS.
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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. We adopted the guidance on January 1, 2010 and it did not have an impact on our 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. Earlier application is prohibited. We adopted the guidance on January 1, 2010 and it did not have an impact on our 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. The adoption did not have any material impact on our consolidated 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 consolidated financial position, results of operations or cash flows.
RESULTS OF OPERATIONS
The following is a discussion of our results of operations for the years ended December 31, 2010 and 2009 and the year ended December 31, 2008 on a combined basis. We believe that presenting combined results of operations for 2008 facilitates a comparison across periods. The 2008 information presented on a combined basis is not comparable to the Predecessor information for the period from January 1, 2008 to December 12, 2008, because it reflects the effects of purchase accounting adjustments related to the Acquisition beginning from the Acquisition date. Refer to the audited consolidated financial statements of the Company included in this Form 20-F for the complete presentation of financial statements for the Predecessor and Successor periods and related footnotes.
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The following table sets forth our consolidated statements of operations for the year ended December 31, 2010, the year ended December 31, 2009, the period from January 1, 2008 to December 12, 2008, the period from December 13, 2008 to December 31, 2008, as well as results of operations for 2008 on a combined basis for the year ended December 31, 2008 (in thousands):
| | Successor | | Combined | | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Year ended
December 31,
2008 | | Period from
December 13,
to
December 31,
2008 | | Period from
January 1,
to
December 12,
2008 | |
Revenue | | | | | | | | | | | |
Products | | $ | 3,253,632 | | $ | 3,162,806 | | $ | 4,425,432 | | $ | 117,501 | | $ | 4,307,931 | |
Services | | 424,356 | | 291,331 | | 358,704 | | 17,970 | | 340,734 | |
Total revenues | | 3,677,988 | | 3,454,137 | | 4,784,136 | | 135,471 | | 4,648,665 | |
Cost of sales, excluding depreciation and amortization | | | | | | | | | | | |
Cost of products | | 3,247,033 | | 3,120,713 | | 4,383,504 | | 113,295 | | 4,270,209 | |
Cost of services | | 259,526 | | 171,708 | | 232,607 | | 11,677 | | 220,930 | |
Total cost of sales, excluding depreciation and amortization | | 3,506,559 | | 3,292,421 | | 4,616,111 | | 124,972 | | 4,491,139 | |
| | 171,429 | | 161,716 | | 168,025 | | 10,499 | | 157,526 | |
Operating expenses | | | | | | | | | | | |
Depreciation of property, plant and equipment | | 64,968 | | 56,564 | | 31,955 | | 3,558 | | 28,397 | |
General and administrative | | 24,935 | | 24,731 | | 31,980 | | 615 | | 31,365 | |
Amortization of intangible assets | | 29,177 | | 25,747 | | 4,432 | | 1,323 | | 3,109 | |
Stock based compensation | | 4,629 | | 8,957 | | — | | — | | — | |
Loss (gain) on sale of property, plant and equipment | | (37 | ) | (90 | ) | (90 | ) | 18 | | (108 | ) |
Impairment of goodwill and intangible assets | | — | | 114,115 | | — | | — | | — | |
Other non-operating expenses (income) | | | | | | | | | | | |
Accretion expense | | 787 | | 785 | | 426 | | 22 | | 404 | |
Foreign exchange gain | | (39,880 | ) | (92,681 | ) | (4,970 | ) | (4,487 | ) | (483 | ) |
Debt extinguishment costs | | — | | 18,517 | | — | | — | | — | |
Loss from investment in associates | | 914 | | 54 | | 357 | | 21 | | 336 | |
Interest expense (income): | | | | | | | | | | | |
Long-term debt | | 96,345 | | 80,169 | | 3,430 | | 3,430 | | — | |
Due to affiliates | | — | | — | | 8,280 | | — | | 8,280 | |
Income | | (324 | ) | (253 | ) | (358 | ) | (12 | ) | (346 | ) |
Other | | 3,106 | | 699 | | 56 | | 1 | | 55 | |
| | 184,620 | | 237,314 | | 75,498 | | 4,489 | | 71,009 | |
Income (loss) before income taxes | | (13,191 | ) | (75,598 | ) | 92,527 | | 6,010 | | 86,517 | |
Income tax expense (recovery) | | (13,346 | ) | (12,649 | ) | 26,229 | | 1,030 | | 25,199 | |
Net income (loss) | | $ | 155 | | $ | (62,949 | ) | $ | 66,298 | | $ | 4,980 | | $ | 61,318 | |
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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. Results for 2008 are presented on a combined basis, which includes the effect of the Acquisition for the period from December 13 to December 31, 2008. The Acquisition primarily affected depreciation and amortization, interest expense and income taxes. However, we do not allocate interest expense, income taxes and depreciation and amortization expense to specific segments; therefore segment profit measure is not affected by the Acquisition. Revenues presented by segment in the table below include inter-segment revenue, as this is considered more indicative of the level of each segment’s activity. Profit by segments excludes depreciation, amortization, accretion, impairment charges and stock based compensation, as we look at each period’s earnings before non-cash depreciation, amortization and stock based compensation as one of our important measures of segment performance.
Revenue and profit by segment for the years ended December 31, 2010, 2009 and 2008 were as follows:
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008
(combined) | |
| | (in thousands) | |
Segment revenue | | | | | | | |
Terminals and pipelines | | $ | 903,100 | | $ | 597,500 | | $ | 889,993 | |
Truck transportation | | 351,568 | | 229,258 | | 301,379 | |
Propane and NGL marketing and distribution | | 759,134 | | 492,360 | | 702,380 | |
Processing and wellsite fluids | | 418,897 | | 335,394 | | 540,407 | |
Marketing | | 2,928,133 | | 2,989,881 | | 3,976,108 | |
Total segment revenue | | 5,360,832 | | 4,644,393 | | 6,410,267 | |
Revenue—inter-segmental | | (1,682,844 | ) | (1,190,256 | ) | (1,626,131 | ) |
Total revenue—external | | 3,677,988 | | 3,454,137 | | 4,784,136 | |
Segment profit | | | | | | | |
Terminals and pipelines | | 40,548 | | 46,924 | | 44,914 | |
Truck transportation | | 53,313 | | 32,797 | | 48,702 | |
Propane and NGL marketing and distribution | | 34,343 | | 38,780 | | 32,163 | |
Processing and wellsite fluids | | 34,143 | | 28,996 | | 29,051 | |
Marketing | | 8,030 | | 13,115 | | 13,552 | |
Total segment profit | | 170,377 | | 160,612 | | 168,382 | |
General and administrative | | 24,935 | | 24,731 | | 31,980 | |
Depreciation and amortization | | 94,145 | | 82,311 | | 36,387 | |
Stock based compensation | | 4,629 | | 8,957 | | — | |
Impairment of goodwill and intangible assets | | — | | 114,115 | | — | |
Accretion expense | | 787 | | 785 | | 426 | |
Foreign exchange gain | | (40,055 | ) | (93,821 | ) | (4,346 | ) |
Debt extinguishment costs | | — | | 18,517 | | — | |
Interest expense, net | | 99,127 | | 80,615 | | 11,408 | |
Income (loss) before income tax | | (13,191 | ) | (75,598 | ) | 92,527 | |
Income tax expense (recovery) | | (13,346 | ) | (12,649 | ) | 26,229 | |
Net income (loss) | | $ | 155 | | $ | (62,949 | ) | $ | 66,298 | |
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.
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Terminals and pipelines
The following tables set forth our operating results from our terminals and pipelines segment:
| | Year ended December 31, | |
Volumes (barrels in thousands) | | 2010 | | 2009 | | 2008 | |
Hardisty | | 68,635 | | 64,182 | | 65,468 | |
Edmonton South | | 17,539 | | 18,316 | | 14,629 | |
Total terminals | | 86,174 | | 82,498 | | 80,097 | |
Custom terminals | | 10,894 | | 10,070 | | 10,776 | |
Injection stations | | 21,604 | | — | | — | |
Bellshill | | 1,893 | | 2,878 | | 3,769 | |
Provost | | 6,998 | | 7,088 | | 7,743 | |
Total pipelines | | 8,891 | | 9,966 | | 11,512 | |
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008
(combined) | |
| | (in thousands) | |
Revenues | | $ | 903,100 | | $ | 597,500 | | $ | 889,993 | |
Cost of sales | | 838,574 | | 526,150 | | 825,258 | |
Operating expenses and other | | 23,978 | | 24,426 | | 19,821 | |
Segment profit | | $ | 40,458 | | $ | 46,924 | | $ | 44,914 | |
Year ended December 31, 2010 and 2009.
Volumes, revenues and cost of sales.
Hardisty Terminal volumes increased 7% in the year ended December 31, 2010, compared to the year ended December 31, 2009 as a result of increased volumes from the Athabasca pipeline, particularly in the fourth quarter of 2010, and also by increased volumes following the acquisition of the remaining interests in BRT. Overall revenues at the Hardisty Terminal increased $2.4 million in the year ended December 31, 2010 compared to the year ended December 31, 2009.
Edmonton South Terminal volumes decreased 4% in the year ended December 31, 2010 compared to the year ended December 31, 2009, largely as a result of a decrease in diesel shipments through the terminal from a major customer, which are subject to minimum volume charges. Offsetting this decrease was an increase in crude volumes, which was largely driven by the increase in volumes from our marketing segment. Revenues at Edmonton South increased by $2.8 million in the year ended December 31, 2010 compared to the year ended December 31, 2009, as a result of the increase in crude volumes. In addition, revenue from our diesel terminalling contracts remained relatively stable because the contracts have fixed fee minimum volume charges.
Custom terminal volumes increased 8% in the year ended December 31, 2010, compared to the year ended December 31, 2009, mainly as a result of increased throughput at our Edmonton South terminal. As a result of the increase in volumes and the overall increase in average prices for crude oil and condensate, revenues increased by approximately $297.9 million in the year ended December 31, 2010 compared to the year ended December 31, 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 and a pipeline located in Texas. Revenue is charged based on volumes that run through the injection stations and the pipeline and was $2.8 million from the date of the acquisition to December 31, 2010.
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Volumes for our Bellshill pipeline were 34% lower in the year ended December 31, 2010 compared to the year ended December 31, 2009, due to a 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 $0.7 million decrease in revenues in the year ended December 31, 2010 compared to the year ended December 31, 2009. However, offsetting the volume decrease was an increase in tariffs, which resulted in a 17% increase in revenue per barrel.
Volumes for our Provost pipeline declined by 1% in the year ended December 31, 2010 compared to the year ended December 31, 2009 despite an increase in volumes in the fourth quarter of 2010 compared to the fourth quarter of 2009, as a result of a new battery being connected to the pipeline in 2010. Tariff increases, however, led to revenue increasing by $0.6 million in the year ended December 31, 2010 compared to the year ended December 31, 2009. As a result of tariff increases, revenue per barrel increased 7% in the year ended December 31, 2010 compared to the year ended December 31, 2009.
Operating expenses and other. Overall operating expenses and other costs decreased by $0.4 million, or 2%. The decrease was related to an unrealized gain recorded in connection with our electricity hedge in the year ended December 31, 2010 of $0.7 million compared to an unrealized loss amount of $2.2 million in the year ended December 31, 2009. Offsetting this were additional operating costs as a result of the Taylor acquisition. Other operating costs remained relatively stable.
Segment profit. Overall, segment profit in the year ended December 31, 2010 decreased by $6.5 million, or 14%, compared to the year ended December 31, 2009. The primary reason for the decrease was due to lower profits being generated from our custom terminals as a result of less favorable blending opportunities, offset by increased profits from our Hardisty and Edmonton South Terminals.
Year ended December 31, 2009 and 2008.
Volumes, revenues and cost of sales.
Hardisty Terminal volumes decreased 2% in the year ended December 31, 2009, compared to the year ended December 31, 2008 as a result of lower volumes from the Athabasca pipeline and from other pipeline sources. Overall revenues increased by $3.7 million in the year ended December 31, 2009 compared to the year ended December 31, 2008 primarily as a result of higher tariffs, which more than offset the decrease in volumes.
Edmonton South Terminal volumes increased 25% in the year ended December 31, 2009 compared to the year ended December 31, 2008, largely as a result of higher diesel shipments through the terminal from a major customer, which are subject to minimum volume charges. Revenues at Edmonton South remained relatively stable in the year ended December 31, 2009 compared to the year ended December 31, 2008, as our diesel terminalling contracts are all fixed fee below a certain minimum volume. Accordingly, revenue per barrel decreased by 21% over the prior year as a result of an increase in volumes that were subject to minimum volume charges.
Custom terminal volumes decreased 7% in the year ended December 31, 2009, compared to the year ended December 31, 2008, as a result of lower producer netbacks caused by a tightening of grade differentials. As a result of the decrease in volumes and the overall decrease in average prices for crude oil and condensate, revenues decreased by approximately $295.0 million in the year ended December 31, 2009 compared to the year ended December 31, 2008, which also resulted in a corresponding decrease in cost of sales.
Volumes for our Bellshill pipeline were 24% lower for the year ended December 31, 2009 compared to the year ended December 31, 2008 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 by truck, which resulted from unfavorable market dynamics for blending. The decrease in volumes was partially offset by tariff increases, but resulted in a $0.4 million decrease in revenues in the year ended December 31, 2009 compared to the year ended December 31, 2008.
Due to natural declines for batteries connected to the pipeline, volumes for our Provost pipeline also declined by 8% for the year ended December 31, 2009 compared to the year ended December 31, 2008, despite one new oil production battery
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coming on stream. Tariff increases, however, led to revenue remaining relatively stable in the year ended December 31, 2009 compared to the year ended December 31, 2008.
Operating expenses and other. Overall operating expenses and other costs increased by $4.6 million, or 23%. This was due to increased operating costs, primarily due to electricity costs increasing as a result of an electricity swap that fixes the price of electricity used by the various operations. In the year ended December 31, 2009, our electricity swap was set at $80.49/megawatt hour compared to $57.00/megawatt hour in the year ended December 31, 2008, thereby resulting in increased actual costs incurred. At December 31, 2009, we had recorded an unrealized loss of $2.1 million relating to the electricity swap compared to an unrealized gain of $0.1 million at December 31, 2008.
Segment profit. Overall, segment profit for the year ended December 31, 2009 increased by $2.0 million, or 4%, compared to the year ended December 31, 2008. The primary reason for the increase was due to improved margins earned offset by increased operating costs.
Truck transportation
The following tables set forth our operating results from our truck transportation segment:
| | Year ended December 31, | |
Volumes (barrels in thousands) | | 2010 | | 2009 | | 2008 | |
Barrels hauled | | 133,235 | | 81,742 | | 84,788 | |
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008
(combined) | |
| | (in thousands) | |
Revenues | | $ | 351,568 | | $ | 229,258 | | $ | 301,379 | |
Cost of sales | | 239,155 | | 151,555 | | 190,926 | |
| | 112,413 | | 77,703 | | 110,453 | |
Operating expenses and other | | 59,100 | | 44,906 | | 61,751 | |
Segment profit | | $ | 53,313 | | $ | 32,797 | | $ | 48,702 | |
Year ended December 31, 2010 and 2009.
Volumes, revenues and cost of sales.
For the year ended December 31, 2010, barrels hauled increased by 63% compared to the year ended December 31, 2009, due mainly to the impact of the acquisition of Taylor, which occurred on May 14, 2010; and to a lesser extent the acquisitions of 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 product demand as a result of favorable commodity pricing.
Revenues increased by 53% in the year ended December 31, 2010 as compared to the year ended December 31, 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 and lease operators. Cost of sales in the year ended December 31, 2010 increased 58%, largely in line with the increase in revenue, as compared to the year ended December 31, 2009.
Operating expenses and other. Overall operating expenses and other costs increased by $14.2 million, or 32%, in the year ended December 31, 2010 compared to the year ended December 31, 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. In particular, the Taylor acquisition contributed an additional $14.2 million to segment profit in the year ended December 31, 2010.
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Year ended December 31, 2009 and 2008.
Volumes, revenues and cost of sales.
For the year ended December 31, 2009, barrels hauled decreased by 4% compared to the year ended December 31, 2008, due to a decrease in volumes from the loss of a major customer, offset by the impact of the acquisition of Bridge Creek, which occurred on May 1, 2009.
Revenues decreased by 24% for the year ended December 31, 2009 as compared to the year ended December 31, 2008, mainly as a result of a decrease in hauling volumes and rates. Crude and condensate hauling was the primary driver of the revenue decrease, resulting from decreased activity and lower rates charged to our customers as a result of the decreased demand for trucking services, as well as lower fuel surcharge revenue.
Cost of sales is primarily comprised of payments to owner-operators. Cost of sales for the year ended December 31, 2009 decreased 21%, as a result of decreased activity, as compared to the year ended December 31, 2008.
Operating expenses and other. Overall operating expenses and other costs decreased by $16.8 million, or 27%, in the year ended December 31, 2009 compared to the year ended December 31, 2008, mainly due to lower overall operating costs as a result of lower overall activity, offset in part by the impact of additional costs related to the Chief and Bridge Creek acquisitions.
Segment profit. Segment profit decreased as a result of the decrease in revenues, mainly driven by lower activity levels and lower hauling rates as a result of increased competition in the sector, which lowered overall margins and also as a result of increased operating expenses.
Propane and NGL marketing and distribution
The following tables set forth operating results from our propane and NGL marketing and distribution segment:
| | Year ended December 31, | |
Volumes | | 2010 | | 2009 | | 2008 | |
Sales volumes—retail (gallons in thousands) | | | | | | | |
Residential | | 5,432 | | 5,884 | | 6,073 | |
Oil and gas | | 36,362 | | 27,787 | | 28,245 | |
Commercial and industrial | | 15,066 | | 15,249 | | 17,346 | |
Automotive | | 6,850 | | 7,496 | | 8,721 | |
Other | | 4,855 | | 4,865 | | 5,373 | |
| | 68,565 | | 61,281 | | 65,758 | |
Sales volumes—wholesale | | | | | | | |
Propane distribution (gallons in thousands) | | 227,334 | | 212,932 | | 212,112 | |
| | | | | | | |
NGL Marketing (barrels in thousands) | | | | | | | |
Propane | | 41 | | 159 | | 271 | |
Butane | | 1,825 | | 665 | | 623 | |
Condensate | | 1,182 | | 1,114 | | 2,204 | |
Taylor | | 1,823 | | — | | — | |
Total sales volumes | | 4,871 | | 1,938 | | 3,098 | |
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| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008
(combined) | |
| | (in thousands) | |
Revenues | | | | | | | |
Retail | | | | | | | |
Propane | | $ | 126,168 | | $ | 104,648 | | $ | 145,522 | |
Other | | 2,462 | | 2,705 | | 3,606 | |
Total retail | | 128,630 | | 107,353 | | 149,128 | |
Wholesale | | | | | | | |
Propane distribution | | 270,026 | | 218,292 | | 293,430 | |
NGL Marketing | | 349,634 | | 157,463 | | 249,573 | |
Total wholesale | | 619,660 | | 375,755 | | 543,003 | |
Other income | | 10,844 | | 9,252 | | 10,249 | |
Total revenues | | 759,134 | | 492,360 | | 702,380 | |
| | | | | | | |
Cost of sales | | | | | | | |
Retail | | | | | | | |
Propane | | 86,446 | | 64,174 | | 106,014 | |
Other | | 1,751 | | 1,963 | | 3,267 | |
Total retail | | 88,197 | | 66,137 | | 109,281 | |
Wholesale | | | | | | | |
Propane distribution | | 255,909 | | 203,252 | | 281,869 | |
NGL Marketing | | 341,260 | | 146,664 | | 243,176 | |
Total wholesale | | 597,169 | | 349,916 | | 525,045 | |
Total cost of sales | | 685,366 | | 416,053 | | 634,326 | |
| | 73,768 | | 76,307 | | 68,054 | |
Operating expenses and other | | 39,425 | | 37,527 | | 35,891 | |
Segment profit | | $ | 34,343 | | $ | 38,780 | | $ | 32,163 | |
Year ended December 31, 2010 and 2009.
Volumes, revenues and cost of sales.
Retail volumes increased 12% in the year ended December 31, 2010 compared to the year ended December 31, 2009, largely as a result of increased volumes in the oil and gas market. The increase in the oil and gas market was the result of an overall increase in drilling activity in the year ended December 31, 2010 compared to the year ended December 31, 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, particularly during the first three months of 2010 compared to the first three months of the 2009. Also, there were declines in the commercial and industrial markets due to declines in construction activity, particularly during the first three months of 2010, 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 20% in the year ended December 31, 2010 as compared to the year ended December 31, 2009, primarily as a result of increased sales volumes and increased rack prices.
Wholesale propane distribution volumes increased by 7% in the year ended December 31, 2010 compared to the year ended December 31, 2009, largely as a result of increased demand in the latter half of 2010 due to the impact of executing an exclusive supply agreement with a major customer. Offset against this was the impact of warmer weather in the current year period, particularly in the first three months of the year, which resulted in a decrease in demand compared to the prior year period. However, revenues increased by 24%, as a result of increased volumes and rack prices.
NGL marketing volumes increased by 151% in the year ended December 31, 2010 as compared to the year ended December 31, 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. NGL marketing revenues increased 122% due mainly to the impact of the Taylor acquisition.
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Cost of sales per gallon in retail propane and wholesale propane distribution increased by 20% and 18%, respectively in the year ended December 31, 2010, due to increased rack prices. Retail propane margin per gallon decreased by 12% as a result of a change in the overall sales mix, as oil and gas 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 year ended December 31, 2010 compared to the year ended December 31, 2009 by 13%. This decrease was largely due to less favorable pricing conditions in the year ended December 31, 2010 compared to the year ended December 31, 2009. In particular, wide pricing differentials between Edmonton and the Puget Sound region existed in the first quarter of 2009, but similar conditions did not exist in the year ended December 31, 2010. In addition, the decrease was also due to an unfavorable impact of a weaker U.S. dollar relative to the Canadian dollar.
Cost of sales for NGL marketing increased by 133% in the year ended December 31, 2010 as compared to the year ended December 31, 2009, largely due to the impact of the Taylor acquisition.
Operating expenses and other. Overall operating expenses and other costs increased by $1.9 million, or 5% in the year ended December 31, 2010 compared to the year ended December 31, 2009, which was largely related to the additional costs from the Taylor acquisition and also due to an increase in payroll related expenses.
Segment profit. The propane and NGL marketing and distribution segment profit decreased in the year ended December 31, 2010 by $4.4 million or 11% as compared to the year ended December 31, 2009 primarily as a result of lower margins in retail propane and wholesale propane distribution and also due to increased operating expenses.
Years ended December 31, 2009 and 2008.
Volumes, revenues and cost of sales.
Retail volumes decreased 7% for the year ended December 31, 2009 compared to the year ended December 31, 2008, largely as a result of decreased volumes across all markets. In particular, declines were experienced in the commercial and industrial markets due to declines in construction activity, in the oil and gas market due to an overall decline in market conditions and business 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 decreased 28% for the year ended December 31, 2009 as compared to the year ended December 31, 2008, primarily as a result of decreased rack prices, which are typically correlated to the price of crude oil and to a lesser extent, reduced sales volumes.
Wholesale propane distribution volumes remained relatively stable in the year ended December 31, 2009 compared to the year ended December 31, 2008, but revenues decreased by 26%, largely as a result of decreased rack prices.
NGL marketing volumes decreased 37% in the year ended December 31, 2009 as compared to the year ended December 31, 2008, primarily as a result of a decrease in product sold to external customers and products used by our marketing segment. NGL marketing revenues decreased 37%.
Cost of sales per gallon in retail and wholesale propane decreased 35% and 28%, respectively, in the year ended December 31, 2009, due to decreased rack prices, which typically move in correlation with changes in the price of crude oil.
Retail propane margin per gallon increased by 10% as a result of increased business in higher margin areas, such as northern British Columbia and northern Alberta. Wholesale propane margin per gallon was higher in the year ended December 31, 2009 compared to the year ended December 31, 2008 by 31% as a result of a favorable pricing differential between Edmonton and the Puget Sound region in the first fiscal quarter of 2009.
Cost of sales for NGL marketing decreased by 40% in the year ended December 31, 2009 as compared to the year ended December 31, 2008, largely in line with the decrease in revenue.
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Operating expenses and other. Overall operating expenses and other costs increased by $1.6 million, or 5%, in the year ended December 31, 2009 compared to the year ended December 31, 2008, primarily due to a foreign exchange loss of $1.3 million in the current year compared to a $0.7 million gain in the prior year.
Segment profit. The propane and NGL marketing and distribution segment profit increased in the year ended December 31, 2009 by $6.6 million or 21% as compared to the year ended December 31, 2008 primarily as a result of improved margins per gallon in both retail and wholesale propane distribution and increased margins in NGL marketing.
Processing and wellsite fluids
The following tables set forth operating results from our processing and wellsite fluids segment for the periods indicated:
| | Year ended December 31, | |
Volumes (barrels in thousands) | | 2010 | | 2009 | | 2008 | |
Roofing flux | | 1,128 | | 1,333 | | 1,680 | |
Road asphalt | | 833 | | 566 | | 486 | |
Frac fluid | | 507 | | 228 | | 317 | |
Tops | | 1,471 | | 1,667 | | 1,555 | |
Distillate | | 533 | | 396 | | 651 | |
Other | | 35 | | 44 | | 30 | |
Total sales volumes | | 4,507 | | 4,234 | | 4,719 | |
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008
(combined) | |
| | (in thousands) | |
Revenues | | | | | | | |
Road asphalt and roofing flux | | $ | 170,141 | | $ | 150,388 | | $ | 213,426 | |
Frac fluid | | 59,699 | | 22,057 | | 63,396 | |
Tops | | 111,563 | | 109,079 | | 154,848 | |
Distillate | | 71,643 | | 49,263 | | 104,487 | |
Other | | 5,851 | | 4,607 | | 4,250 | |
Total revenues | | 418,897 | | 335,394 | | 540,407 | |
Cost of sales | | 365,995 | | 291,712 | | 491,069 | |
Operating expenses and other | | 18,759 | | 14,686 | | 20,287 | |
Segment profit | | $ | 34,143 | | $ | 28,996 | | $ | 29,051 | |
Year ended December 31, 2010 and 2009.
Volumes, revenues and cost of sales.
Sales volumes for roofing flux and road asphalt increased 3% in the year ended December 31, 2010 compared to the year ended December 31, 2009, largely driven by increases in road asphalt. Road asphalt sales volumes increased mainly as a result of an increase in overall paving projects, due in part to an increase in government spending and despite wet weather conditions during the paving season in Saskatchewan. Roofing flux volume declined as a result of a continued decline in the U.S. roofing market. Road asphalt and roofing flux revenue increased by 13% in the year ended December 31, 2010 compared to the year ended December 31, 2009 largely due to an increase in average asphalt prices and also due to the increase in volumes.
Frac fluid revenues were 171% higher in the year ended December 31, 2010 compared to the year ended December 31, 2009, which was attributable to higher volumes. Frac fluid volumes increased 122% in the year ended December 31, 2010 compared to the year ended December 31, 2009. This increase was primarily due to increased market demand for frac fluid due to a general increase in activity levels, including increased drilling activity in the WCSB.
Tops volumes were 12% lower in the year ended December 31, 2010 as compared to the year ended December 31, 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
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increase, we move less of the light volume product as tops. However, tops revenues were 2% higher over the same period, reflecting the higher price of crude oil, which is the basis for pricing tops.
Sales volumes for distillate were 35% higher in the year ended December 31, 2010 compared to the year ended December 31, 2009 due to an increase in drilling activity. Distillate revenues were 45% higher in the period as a result of higher volumes and higher distillate prices.
The overall cost per barrel for the basket of products sold by the processing and wellsite segment increased by 18% due to increased crude costs as discussed above.
Overall margins increased by $9.2 million, or 21%, in the year ended December 31, 2010 as compared to the year ended December 31, 2009. The primary reason for the increase in overall margins was largely related to an increase in margins for our wellsite fluids, which was a result of increased overall demand. Offset against this was a decrease in roofing flux margins, which was negatively impacted by lower volumes.
Operating expenses and other. Operating expenses increased by $4.1 million or 28% in the year ended December 31, 2010 as compared to the year ended December 31, 2009, primarily due to an increase in safety and maintenance expenses and also due to lower foreign exchange gains of $0.3 million in the year ended December 31, 2010 compared to a foreign exchange gain of $1.1 million in the year ended December 31, 2009.
Segment profit. The processing and wellsite fluids segment profit increased in the year ended December 31, 2010 by $5.1 million or 18% as compared to the year ended December 31, 2009 primarily as a result of an increase in margins and volumes for our wellsite fluids products, offset by a decrease in overall margins for roofing flux and an increase in operating expenses.
Years ended December 31, 2009 and 2008.
Volumes, revenues and cost of sales.
Sales volumes for roofing flux and road asphalt declined 12% in the year ended December 31, 2009 compared to the year ended December 31, 2008. Roofing flux sales declined as a result of an overall decline in activity in the U.S. roofing market. However, road asphalt sales increased as a result of an increase in the number of paving contracts, particularly in Saskatchewan, due to government stimulus spending. Road asphalt and roofing flux revenue declined by 30% in the year ended December 31, 2009 compared to the year ended December 31, 2008 largely due to a decline in average asphalt prices and also due to the decline in volumes.
Frac fluid revenues were 65% lower in the year ended December 31, 2009 compared to the year ended December 31, 2008, which was attributable to decreased volumes and the lower price of frac fluid. Frac fluid volumes decreased 28% for the year ended December 31, 2009 compared to the year ended December 31, 2008. This decline was primarily due to decreased market demand for the product due to a general decline in activity levels and reduced drilling activity.
Tops volumes were 7% higher for the year ended December 31, 2009 as compared to the year ended December 31, 2008. However, tops revenues were 30% lower over the same period, reflecting the lower price of crude oil, which is the basis for pricing tops.
Sales volumes for distillate were 39% lower for the year ended December 31, 2009 as compared to the year ended December 31, 2008 due to lower drilling activity. Distillate revenues were 53% lower in the period as a result of lower distillate prices and lower volumes.
The overall cost per barrel for the basket of products sold by Moose Jaw was reduced by 34% due to decreased crude costs as discussed above.
Overall margins decreased by $5.7 million, or 11%, in the year ended December 31, 2009 as compared to the year ended December 31, 2008. The primary reason for the decrease in overall margins was a result of lower overall activity, particularly in roofing flux. This was partially offset by more favorable pricing terms with our major customers for road asphalt and
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roofing flux sales and increased margins due to strong market demand for road asphalt driven by government stimulus spending.
Operating expenses and other. Operating expenses decreased by $5.6 million or 28% for the year ended December 31, 2009 as compared to the year ended December 31, 2008, primarily due to a foreign exchange gain of $1.1 million in the current year compared to a loss of $3.7 million in the prior year and also due to an accounts receivable write-off of $1.4 million in the prior year.
Segment profit. Segment profits were relatively stable in the year ended December 31, 2009 compared to the year ended December 31, 2008, whereby the margin decrease was offset by the decrease in operating expenses.
Marketing
The following tables set forth our operating results from our marketing segment for the periods indicated:
| | Year ended December 31, | |
Volumes (barrels in thousands) | | 2010 | | 2009 | | 2008 | |
Sales Volumes | | | | | | | |
Crude and diluent | | 47,189 | | 46,983 | | 40,217 | |
Natural gas (GJ) | | 34,869 | | 89,600 | | 73,252 | |
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008
(combined) | |
| | (in thousands) | |
Revenues | | | | | | | |
Crude and diluent | | $ | 2,424,445 | | $ | 2,305,188 | | $ | 3,084,272 | |
Natural gas | | 168,367 | | 397,422 | | 559,826 | |
Edmonton North | | 335,321 | | 287,271 | | 332,010 | |
Total revenues | | 2,928,133 | | 2,989,881 | | 3,976,108 | |
Cost of sales | | 2,908,153 | | 2,964,879 | | 3,954,240 | |
Operating expenses and other | | 11,950 | | 11,887 | | 8,316 | |
Segment profit | | $ | 8,030 | | $ | 13,115 | | $ | 13,552 | |
Year ended December 31, 2010 and 2009.
Volumes, revenues and cost of sales.
The monthly average NYMEX benchmark price of crude oil ranged from approximately U.S.$74.12 to U.S.$89.23 during the year ended December 31, 2010 and from approximately U.S.$39.26 to U.S.$78.15 during the year ended December 31, 2009.
Sales volumes for crude and diluent remained relatively stable in the year ended December 31, 2010 compared to the year ended December 31, 2009. However, revenues for crude and diluent increased by 5% due to higher commodity prices in the year ended December 31, 2010 as compared to the year ended December 31, 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 61% in the year ended December 31, 2010 as compared to the year ended December 31, 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 58% lower in the year ended December 31, 2010 as compared to the year ended December 31, 2009.
Cost of sales in the year ended December 31, 2010 was 2% lower than in the year ended December 31, 2009. This was largely in line with the decrease in revenue.
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Operating expenses and other. Operating expenses increased $0.1 million in the year ended December 31, 2010 compared to the year ended December 31, 2009. The increase was mainly due to additional costs that were incurred to operate a tank from the Battle River Terminal in the year ended December 31, 2010, as the tank did not operate in the prior year until May 2009, offset by a decrease of $0.8 million in the foreign exchange loss recorded in the year ended December 31, 2010 compared to the year ended December 31, 2009.
Segment profit. Overall segment profit decreased by approximately $5.1 million, or 39%, in the year ended December 31, 2010 as compared to the year ended December 31, 2009. In the year ended December 31, 2010 margins were negatively impacted by the narrowing of 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 particularly 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.
Years ended December 31, 2009 and 2008.
Volumes, revenues and cost of sales.
The monthly average NYMEX benchmark price of crude oil ranged from approximately U.S.$39.26 to U.S.$78.15 during the year ended December 31, 2009 and from approximately U.S.$42.04 to U.S.$134.02 during the year ended December 31, 2008.
Sales volumes for crude and diluent increased by 17% in the year ended December 31, 2009, due to increased volumes at our Edmonton North Terminal. However, revenues for crude and diluent decreased by 25% due to lower commodity prices in the year ended December 31, 2009 as compared to the year ended December 31, 2008. 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 increased 22% in the year ended December 31, 2009 as compared to the year ended December 31, 2008, primarily due to increased transactions with other gas marketing companies and also due to a growing customer base, with most of this growth in Ontario, Canada. However, natural gas revenues were 29% lower for the year ended December 31, 2009 as compared to the year ended December 31, 2008 due to lower natural gas prices.
Cost of sales for the year ended December 31, 2009 was 25% lower than for the year ended December 31, 2008. This was mainly attributable to a decrease in the prices at which we were able to purchase product and is consistent with the decrease in revenues.
Operating expenses and other. Operating expenses increased by $3.6 million largely due to a foreign exchange loss of $0.9 million in the year ended December 31, 2009 compared to a foreign exchange gain of $3.6 million in the year ended December 31, 2008. Offsetting this are lower overall operating costs, including a decrease in bad debt expense of $0.9 million that was as a result of an accounts receivable write-off in the year ended December 31, 2008.
Segment profit. Overall segment profit decreased by approximately $0.4 million, or 3%, in the year ended December 31, 2009 as compared to the year ended December 31, 2008. In the year ended December 31, 2009 segment profit was largely driven by activity in the first quarter of 2009. During the first quarter of 2009, 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 quarter, the WTI forward curve was in steep contango, which enabled us to realize profits on financial instruments used to price protect our inventory. In 2008, the volatile market led to favorable basis differentials for various delivery points and grades of crude oil during the first several months of 2008, however,
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margins in the latter half of 2008 were negatively impacted by the declining price of crude and a narrowing of the pricing differentials between crude types.
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 $24.9 million and $24.7 million in the year ended December 31, 2010 and 2009, respectively. The increase in the year ended December 31, 2010 compared to the year ended December 31, 2009 was largely related to a $2.5 million charge in the year ended December 31, 2010 as a result of the company subleasing excess office space at less than cost. In addition, the increase was also due to increased rent expense as we increased our overall office space. However, these were offset by a non-recurring reorganization cost of $3.2 million incurred in the year ended December 31, 2009 and a decrease in payroll related expenses.
G&A expense was $24.7 million and $32.0 million for the year ended December 31, 2009 and 2008, respectively. The decrease was mainly due to costs incurred in the year ended December 31, 2008, associated with the acceleration of compensation plans as a result of the Acquisition.
Depreciation and amortization
Depreciation and amortization expense was $94.1 million and $82.3 million in the year ended December 31, 2010, and 2009, respectively. The increase relates primarily to the additional depreciation and amortization related to our acquisitions, primarily with respect to Taylor, BRT, Johnstone and Aarcam.
Depreciation and amortization expense was $82.3 million and $36.4 million for the year ended December 31, 2009 and 2008, respectively. The increase was due to the impact of the Acquisition and the application of purchase accounting, whereby our assets were adjusted to their fair values on the Acquisition date.
Stock based compensation
Stock based compensation expense was $4.6 million and $9.0 million in the year ended December 31, 2010 and 2009, respectively. The decrease in expense in the year ended December 31, 2010 was largely due to the graded recognition of stock based compensation expense. Under graded recognition, each vesting installment is accounted for as a separate arrangement and expense is recognized over each installment’s vesting period. Therefore, under graded recognition, larger stock based compensation expense is recognized in earlier periods and lower amounts in future periods thereby resulting in higher expense in the year ended December 31, 2009 compared to the year ended December 31, 2010.
Stock based compensation expense was $9.0 million in the year ended December 31, 2009 compared to no expense in the prior year periods. The expense in the year ended December 31, 2009 was due to our adoption of an equity incentive plan in the year and granting options under the plan. In the prior year, we did not have our own equity incentive plan.
Impairment of goodwill and intangible assets
There was no impairment of goodwill and intangible assets in the year ended December 31, 2010.
In the year ended December 31, 2009, we recorded an impairment loss within our truck transportation segment of $85.5 million relating to goodwill and $28.6 million relating to intangible assets. During the fourth quarter of 2009, we compared the fair value of each segment to its book value to determine if there was any goodwill impairment. As a result of this step, it was determined that the fair value of the truck transportation segment was less than its book value, and therefore a second test was performed to determine the amount of any impairment. The amount of the impairment was determined by deducting the fair value of the reporting unit’s individual assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill.
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The excess of the book value of goodwill over the implied fair value of goodwill of $85.5 million was recorded as an impairment loss in the year ended December 31, 2009.
In addition, we also reviewed intangible assets for impairment and concluded that the estimated net recoverable amount of customer relationships and brands within the truck transportation segment were less than the net carrying amount. Therefore, we recorded an impairment of $28.6 million to the asset’s fair value in the year ended December 31, 2009.
These impairment losses were caused by a general market downturn and increased market competitiveness in the truck transportation industry. As a result, it was necessary to reduce the current forecasted cash flows from this segment as compared to previous cash flow forecasts. It is uncertain if industry activity or pricing will return to levels seen in 2007 and 2008 and thus, a return to these levels was not built into the determination of the fair value of the truck transportation segment.
There was no impairment of goodwill or intangible assets in the year ended December 31, 2008.
Foreign exchange gain not affecting segment profit
In the year ended December 31, 2010, we recorded a foreign exchange gain of $40.0 million, compared to a gain of $93.8 million in the year ended December 31, 2009. The gains recorded in each year were primarily due to favorable movement in exchange rates related to our U.S. dollar denominated debt. The decrease in the gains in the current year period was due to smaller movements in exchange rates compared to the prior year periods.
In the year ended December 31, 2009, we recorded a foreign exchange gain of $93.8 million compared to a gain of $4.3 million in the year ended December 31, 2008. The gain recorded in each year was primarily as a result of a favorable movement in exchange rates relating to our U.S. dollar denominated long-term debt.
Debt extinguishment costs
In the year ended December 31, 2009, we recorded debt extinguishment costs of $18.5 million relating to the Refinancing. The amount represents the write-off of our unamortized deferred debt issue costs from the repayment of our Bridge Loans.
Interest expense, net
Interest expense, net was $99.1 million and $80.6 million for the year ended December 31, 2010 and 2009, respectively. The increase in the current year period was primarily due to the increase in our outstanding long-term debt, as a result of the issuance of our Senior Notes in January 2010.
Interest expense, net was $80.6 million the year ended December 31, 2009 compared to $11.4 million in the year ended December 31, 2008. The increase is as a result of the increase in our long-term debt as a result of the Acquisition.
Income tax expense
Income tax recovery was $13.3 million and $12.6 million in the year ended December 31, 2010 and 2009, respectively. The effective tax rate was 101.2% and 16.7% during the year ended December 31, 2010 and 2009, respectively. The effective tax rate in the year ended December 31, 2010 was adjusted for the impact of non-taxable dividends, the rate differential on foreign taxes and by the non-taxable portion of foreign exchange gains. The effective tax rate in the year ended December 31, 2009 was largely impacted by the non-taxable portion of a realized capital gain of $61.4 million, the non-taxable portion of foreign exchange gains which were offset by the non deductibility of the goodwill and intangible impairment charge. The increase in the income tax recovery in the year ended December 31, 2010 compared to the year ended December 31, 2009, was largely as a result of the impact of the non deductibility of the goodwill and intangible impairment charge in the year ended December 31, 2009 offset by the decrease in the loss before tax in the current year.
Income tax during the year ended December 31, 2009 was a recovery of $12.6 million compared to an expense of $26.2 million in the year ended December 31, 2008. The effective tax rate was 16.7% during the year ended December 31, 2009, compared to 28.3% during the year ended December 31, 2008. The main reason for the decrease in the income tax
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provision and the effective tax rate for the year ended December 31, 2009 compared to the prior year period was due the a loss before tax in the current year compared to income before tax in the prior year and the tax impact on a foreign exchange gain on our long term debt offset by the non deductibility of the goodwill impairment charge.
SUMMARY OF QUARTERLY RESULTS
| | 2010 | | 2009 | |
| | Three months ended | |
| | December 31,
2010 | | September 30,
2010 | | June 30,
2010 | | March 31,
2010 | | December 31,
2009 | | September 30,
2009 | | June 30,
2009 | | March 31,
2009 | |
| | (in thousands) | |
Revenues | | $ | 983,474 | | $ | 882,233 | | $ | 848,044 | | $ | 964,237 | | $ | 988,702 | | $ | 875,164 | | $ | 820,438 | | $ | 769,833 | |
Net income (loss) | | 30,231 | | 9,563 | | (49,532 | ) | 9,893 | | (97,181 | ) | 26,714 | | 12,856 | | (5,338 | ) |
EBITDA(1) | | 83,949 | | 59,468 | | (19,359 | ) | 56,347 | | (69,423 | ) | 72,065 | | 49,060 | | 35,879 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
(1) EBITDA consists of net income (loss) before interest expense, income taxes, depreciation, and amortization. You are encouraged to evaluate each adjustment and the reasons we consider it appropriate for supplemental analysis.
We present EBITDA because we consider it to be an important supplemental measure of our performance and believe this measure is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industries with similar capital structures. We believe issuers of “high yield” securities also present EBITDA because investors, analysts and rating agencies consider it useful in measuring the ability of those issuers to meet debt service obligations. We believe that EBITDA is an appropriate supplemental measure of debt service capacity, because cash expenditures for interest are, by definition, available to pay interest, and income tax expense is inversely correlated to interest expense because income tax expense goes down as deductible interest expense goes up and depreciation and amortization are non-cash charges.
EBITDA has limitations as an analytical tool, and you should not consider this item in isolation, or as a substitute for an analysis of our results as reported under 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:
| | 2010 | | 2009 | |
| | Three months ended | |
| | December 31,
2010 | | September 30,
2010 | | June 30,
2010 | | March 31,
2010 | | December 31,
2009 | | September 30,
2009 | | June 30,
2009 | | March 31,
2009 | |
| | (in thousands) | |
Net income (loss) | | $ | 30,231 | | $ | 9,563 | | $ | (49,532 | ) | $ | 9,893 | | $ | (97,181 | ) | $ | 26,714 | | $ | 12,856 | | $ | (5,338 | ) |
Depreciation and amortization | | 25,920 | | 25,339 | | 23,154 | | 19,732 | | 20,360 | | 21,505 | | 19,778 | | 20,668 | |
Interest expense | | 25,523 | | 25,204 | | 24,806 | | 23,918 | | 19,383 | | 19,388 | | 20,758 | | 21,339 | |
Income tax expense (recovery) | | 2,275 | | (638 | ) | (17,787 | ) | 2,804 | | (11,985 | ) | 4,458 | | (4,332 | ) | (790 | ) |
EBITDA | | $ | 83,949 | | $ | 59,468 | | $ | (19,359 | ) | $ | 56,347 | | $ | (69,423 | ) | $ | 72,065 | | $ | 49,060 | | $ | 35,879 | |
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In addition, we present Pro Forma Adjusted EBITDA because it is used in calculating our covenant compliance under the indentures governing our Notes. 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 consolidated net income (loss) before interest expense, income taxes, depreciation, amortization, accretion expense, 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 December 31, 2009, debt extinguishment costs and other adjustments that are considered non-recurring in nature.
The covenants in our indentures 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 December 31, 2010 was $92.8 million. For the twelve months ended December 31, 2009, 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 year ended December 31, 2010:
| | Successor | |
| | Three months ended | | Year ended | |
| | December 31,
2010 | | September 30,
2010 | | June 30,
2010 | | March 31,
2010 | | December 31,
2010 | |
| | (in thousands) | |
EBITDA | | $ | 83,949 | | $ | 59,468 | | $ | (19,359 | ) | $ | 56,347 | | $ | 180,405 | |
Unrealized foreign exchange loss (gain) on long term debt(a) | | (26,752 | ) | (23,408 | ) | 34,200 | | (20,800 | ) | (36,760 | ) |
Net unrealized loss (gain) from financial instruments(b) | | (1,764 | ) | 1,681 | | (1,986 | ) | 696 | | (1,373 | ) |
Employee stock option plan(c) | | 475 | | 1,744 | | 1,260 | | 1,150 | | 4,629 | |
Accretion expense (d) | | 199 | | 195 | | 193 | | 200 | | 787 | |
Recent acquisitions(e) | | — | | 414 | | 2,627 | | 5,286 | | 8,327 | |
EBITDA adjustments relating to associates (f) | | 449 | | 410 | | 634 | | 702 | | 2,195 | |
Management fee(g) | | 255 | | 260 | | 256 | | 271 | | 1,042 | |
Non-recurring charges(h) | | — | | 2,543 | | — | | — | | 2,543 | |
Pro Forma Adjusted EBITDA(i) | | $ | 56,811 | | $ | 43,307 | | $ | 17,825 | | $ | 43,852 | | $ | 161,795 | |
(a) Non-cash adjustment representing the unrealized foreign exchange loss (gain) on long-term debt, as a result of the movement in exchange rates in the periods.
(b) Reflects the exclusion of the change in net unrealized gains or losses attributable to movement in the mark-to-market valuation of financial instruments used in commodity price risk management activities. We use oil and gas price futures, options and swaps to manage the exposure to oil and gas price movements and foreign currency forward contracts and options to manage foreign exchange risks, although we do not formally designate these financial instruments as hedges for Canadian GAAP or U.S. GAAP accounting purposes. Accordingly, the unrealized gains or losses on these financial instruments are recorded directly to the income statement. Management believes that this adjustment better correlates the effect of risk management activities to the underlying operating activities to which they relate.
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(c) Represents stock based compensation expense relating to our equity incentive plan.
(d) Represents accretion expense recorded in connection with our asset retirement obligations.
(e) Reflects the pro forma effect of our acquisitions of Johnstone, Aarcam, Taylor and the remaining 75% interest in BRT on our Pro Forma Adjusted EBITDA as if the acquisitions took place on January 1, 2010.
(f) Represents the adjustment to add back interest expense, income taxes, depreciation and amortization that is included in our share of the results from associates.
(g) Reflects an adjustment for the management fee payable to Riverstone.
(h) Represents a $2.5 million charge in the three months ended September 30, 2010 as a result of the Company subleasing excess office space at less than the amount payable on the head lease.
(i) Pro Forma Adjusted EBITDA represents the amount used in our covenant compliance calculation at December 31, 2010 under the indentures governing our Notes.
LIQUIDITY AND CAPITAL RESOURCES
Our primary liquidity and capital resource needs are to service our debt, including interest payments, to finance working capital needs, to fund ongoing capital expenditures and to fund growth opportunities and acquisitions. We rely on our cash flow from operations, debt financings and borrowings under our Credit facility for liquidity.
We believe that we have sufficient liquidity at December 31, 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, but 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 years ended December 31, 2010, 2009 and 2008:
| | Year ended December 31, | |
| | 2010 | | 2009 | | 2008
(combined) | |
| | (in thousands) | |
Statement of Cash Flows | | | | | | | |
Cash flows provided by (used in): | | | | | | | |
Operating activities | | $ | 51,660 | | $ | 2,070 | | $ | 110,885 | |
Investing activities | | (281,735 | ) | (95,203 | ) | (1,026,126 | ) |
Financing activities | | 212,844 | | (6,444 | ) | 1,020,157 | |
| | | | | | | | | | |
Cash provided by operating activities
The primary drivers of cash flow from operating activities are the collection of amounts related to sales of crude oil, propane, asphalt and other products and fees for services provided associated with our truck transportation and terminal and pipeline services. Offsetting these collections are payments for purchases of crude oil and other products and other expenses. These other expenses primarily consist of owner operator and lease operator payments for the provision of contract trucking services, field operating expenses and 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.
Since the beginning of 2009, 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. In addition, as a result of our outstanding long-term debt, additional cash is required to pay our interest obligations. Interest is payable semi-annually, with interest on our First Lien Notes due on June 1 and December 1, and interest on our Senior Notes due on January 15 and July 15.
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Cash provided by operations was $51.6 million and $2.1 million in the years ended December 31, 2010 and 2009, respectively. The increase in cash provided by operations in the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily attributable to less cash being used for working capital. Despite the increase in inventory of $79.1 million in the year ended December 31, 2010, a significant amount of the increase occurred in December 2010, which also resulted in an overall increase in accounts payable and accrued charges in the month, thereby resulting in settlement in 2011. In addition, deferred revenue increased by $41.3 million in the year ended December 31, 2010 compared to $5.0 million in the year ended December 31, 2009. Inventory increased by $41.6 million in the year ended December 31, 2009 which largely occurred throughout the year. Offset against this was an increase in interest paid in the year ended December 31, 2010 as a result of the issuance of the Senior Notes in January 2010.
Cash provided by operations in the year ended December 31, 2009 was $2.1 million compared to $110.9 million provided by operations in the year ended December 31, 2008. The decrease was primarily attributable to increased interest expense paid and a significant increase in cash used to fund working capital in the year ended December 31, 2009 compared to the year ended December 31, 2008, that was largely driven by an increase in inventory of $41.6 million in the year ended December 31, 2009 compared to a decrease in inventory of $38.6 million in the year ended December 31, 2008. The increase in inventory was mainly due to increases in commodity prices as compared to prices at December 31, 2008.
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 year ended December 31, 2010 and 2009 was $281.7 million and $95.2 million, respectively. The increase was primarily as a result of an increase in business acquisitions in the year ended December 31, 2010 compared to the year ended December 31, 2009. Total business acquisitions, including equity investments, in the year ended December 31, 2010 were $235.8 million, compared to $21.8 million in the year ended December 31, 2009. In the year ended December 31, 2010, we acquired 100% of the outstanding units of Taylor for $153.2 million; 75% of the common shares in BRT for $54.8 million and 100% of the common shares of Johnstone for $21.3 million and Aarcam for $3.4 million. In addition, we participated in a private placement with Palko for $3.0 million, thereby allowing us to maintain our 39% equity interest. In the year ended December 31, 2009, we acquired 100% of the outstanding common shares of Bridge Creek for $6.9 million, acquired the wholesale propane business and assets of the Washington and Oregon operations of Turner for $1.6 million, and also acquired certain propane terminal facilities and the associated businesses in Montana and South Dakota from Superior Propane for $6.7 million. In addition, we also acquired an equity interest of approximately 39% in Palko for $6.6 million.
Cash used in investing activities in the year ended December 31, 2009 was $95.2 million compared to $1,026.1 million in the year ended December 31, 2008. The decrease was primarily as a result of the Acquisition by Riverstone in the year ended December 31, 2008. Total business acquisitions, including equity investments, for the year ended December 31, 2009 and 2008 were $21.8 million and $18.2 million, respectively. In addition, we committed to fund the construction of the Battle River Terminal, of which our 25% share of the funding was approximately $18.0 million. As of December 31, 2009, we had loaned BRT $14.2 million for which there are no fixed repayment terms.
Total capital expenditures for the years ended December 31, 2010, 2009 and 2008 were $61.7 million, $37.0 million, and $46.7 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 year ended December 31, 2010 was $212.8 million, compared to $6.4 million in the year ended December 31, 2009. The cash provided by financing in the year ended December 31, 2010 was largely 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 and discount costs of $12.2 million. In the year ended December 31, 2010, we also had drawn $298.3 million against our Credit facility that was offset by repayments of $279.8 million. The cash provided by financing in the year ended December 31, 2009 was a result of our drawing $25.0 million against the Credit facility, offset by the issuance of the First Lien Notes in an aggregate principal amount of U.S.$560.0 million, the proceeds of which were used to repay the Bridge Loans in full, which totaled U.S.$545.0 million (the “Bridge Loan Refinancing”). Additionally, in connection with the issuance of the First Lien Notes, we paid debt issuance costs and a debt discount totalling $34.0 million.
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Cash provided by financing activities in the year ended December 31, 2009 was $6.4 million, compared to $1,020.2 million provided by financing in the year ended December 31, 2008. The cash provided by financing in the year ended December 31, 2009 was a result of our drawing $25.0 million against the Credit facility, offset by the Bridge Loan Refinancing. Additionally, in connection with the issuance of the First Lien Notes, we paid debt issuance costs and a debt discount totalling $34.0 million. Total cash provided by financing activities in the year ended December 31, 2008 was $1,020.2 million. As a result of the Acquisition, we were capitalized with cash of $537.7 million and we entered into Bridge Loan facilities, pursuant to which lenders extended Bridge Loans comprising of U.S.$230.0 million of first lien senior secured interim loans and U.S.$315.0 million of second lien senior secured interim loans.
As of December 31, 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 material wholly owned subsidiaries. Additionally, we have a Credit facility of up to U.S.$200.0 million, the proceeds of which are available to provide financing for working capital and other general corporate purposes. At December 31, 2010, we had $43.5 million drawn against this facility and we had issued letters of credit totalling $59.2 million. At December 31, 2010, we had restricted cash of $6.1 million.
At December 31, 2009, the maximum amount under the Credit facility was U.S.$95.0 million. On January 19, 2010 we increased the maximum amount under the Credit facility to U.S.$150.0 million. On September 17, 2010, we amended and restated our Credit facility to (i) increase the amount available by U.S.$50.0 million resulting in an aggregate available amount of $U.S.$200.0 million; (ii) increase the letter of credit subfacility by U.S.$25.0 million, resulting in an aggregate available amount of the letter of credit subfacility of U.S.$100.0 million; (iii) establish a U.S. subfacility of up to U.S.$30.0 million to be used for our U.S. operations, which includes, among other things, a separate borrowing base supported by the assets of certain U.S. subsidiaries of the Company; (iv) permit Royal Bank of Canada, as a lender under the Credit facility, to front letters of credit under the letter of credit subfacility up to an amount of U.S.$50.0 million; (v) permit PNC Bank, N.A. or its affiliates to become a lender under the Credit facility in an amount up to U.S.$40.0 million and to front letters of credit under the letter of credit subfacility up to an amount of U.S.$30.0 million; (vi) permit Bank of Montreal to increase its commitment under the Credit facility to U.S.$40.0 million; and (vii) to add the various U.S. subsidiaries of the Company as additional U.S. borrowers under the Credit facility, in each case subject to certain limitations set forth in the Credit facility. We are currently utilizing U.S.$10.0 million relating to the U.S. subfacility, with the remainder of the U.S.$200.0 million available for use by our Canadian operations.
The term of our Credit facility requires us to maintain a “Fixed Charge Coverage Ratio” of not less than 1.1:1, following any period of 3 consecutive days in which availability is less than an amount equal to 15% of the commitments by the lenders under the Credit facility. As of December 31, 2010, we had $43.5 million drawn and issued letters of credit of $59.2 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 Credit facility. An event of default resulting from a breach of a financial covenant may result, at the option of lenders holding a majority of the loans, in an acceleration of repayment of the principal and interest outstanding and a termination of the Credit facility, and could result in an acceleration of amounts due and payable under the Notes. In addition, the facility contains a provision that requires prior written consent for acquisitions exceeding annual consideration of U.S.$80.0 million, exclusive of acquisitions funded by permitted equity or debt raised to finance such transactions.
The Notes and the Credit facility also contain non-financial covenants that restrict some of our activities, including our ability to dispose of assets, incur additional debt, pay dividends, create liens, make investments and engage in specified transactions with affiliates. In connection with the First Lien Notes, following the sale of our Edmonton North Terminal, we are required to acquire collateral assets of approximately $55.0 million within 545 days after the sale. The Notes and the Credit facility also contain customary events of default, including defaults based on events of bankruptcy and insolvency, non-payment of principal, interest or fees when due, subject to specified grace periods, breach of specified covenants, change in control and material inaccuracy of representations and warranties. As of December 31, 2010, we were in compliance with all of our non-financial covenants under our Notes and Credit facility.
Prior to the Acquisition on December 12, 2008, the primary component of our long-term debt balances were amounts drawn under committed and uncommitted loan facilities with Hunting Knightsbridge Holdings Ltd., a wholly owned subsidiary of
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Hunting. The interest rate applicable to $18.5 million of this balance was at the Royal Bank of Canada’s prime rate plus 1.625%. The balance of these loans incurred interest at 1.5% over the three-month Canadian Dollar LIBOR (London InterBank Offered Rate). These borrowing facilities were terminated in connection with the Acquisition. Additionally, we also had access to revolving demand credit facilities with a total maximum borrowing amount of $30.0 million, or the equivalent amount in U.S. dollars. These credit facilities were not utilized in the year ended December 31, 2008, except for issued letters of credit supported by the facility. Amounts outstanding under the facilities bear interest at the Royal Bank of Canada or Toronto Dominion Bank prime rate. These facilities were terminated in connection with the Acquisition.
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 facility, will be adequate to meet our working capital needs, planned capital expenditures, debt service and other cash requirements for at least the next year. At December 31, 2010, we had unrestricted cash of $1.1 million and $96.2 million available under the Credit facility. In addition, on January 7, 2011, we disposed of our Edmonton North Terminal for consideration of approximately $54.3 million. We used the consideration to repay the amount drawn on our Credit facility. As of December 31, 2010, we had $43.5 million drawn and issued letters of credit of $59.2 million against the Credit facility.
Our ability to make scheduled payments of principal, to pay interest on and to refinance our indebtedness, and to fund our other liquidity requirements will depend on our ability to generate cash in the future. Capital expenditures amounted to $61.7 million and acquisitions, including equity investments amounted to $235.8 million during the year ended December 31, 2010. We have identified and approved additional capital projects (excluding acquisitions) of $165.3 million that we expect to undertake over the next 12 to 18 months. While we anticipate that these capital expenditures and acquisitions will occur, they are subject to general economic, financial, competitive, legislative, regulatory and other factors, some of which are beyond our control.
In addition to anticipated capital expenditures and acquisitions, we may engage in additional strategic acquisitions and capital expenditures as opportunities arise that benefit our existing operations by expanding our reach in existing markets or by providing platforms with which to enter new markets. Any such acquisition or capital expenditure could be material and could have a material effect on our liquidity, cash flows and capital commitments and resources. Any future acquisitions, capital expenditures or other similar transactions will likely require additional capital and there can be no assurance that any such capital will be available to us on acceptable terms, if at all.
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. On April 27, 2011, our affiliate Gibson Energy Inc. filed a preliminary prospectus with the securities regulatory authority in each of the provinces and territories of Canada. We intend to use the proceeds from the Offering and the Refinancing to offer to purchase for cash any and all of our outstanding First Lien Notes and Senior Notes and to repay any amounts outstanding under the Credit facility.
Additionally, the indentures governing the Notes limit our ability to incur additional indebtedness or to make certain acquisitions unless we meet or exceed a consolidated interest coverage ratio, which is based in part on our Pro Forma Adjusted EBITDA during the 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 interest coverage ratio. As a result of the issuance of the Senior Notes, at December 31, 2010, we did not meet this ratio and we expect that we will not be able to meet this ratio at certain times in 2011.
Contingencies
Two of our subsidiaries 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.
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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. As of December 31, 2010, our undiscounted cash flows to settle future liabilities was $81.6 million.
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 December 31, 2010, our obligations and commitments to make future payments under contracts and contingent commitments:
| | Payments due by period | |
(in thousands) | | Total | | Less than 1 year | | 1-3 years | | 3-5 years | | More than
5 years | |
Long-term debt(1) | | $ | 755,896 | | $ | — | | $ | — | | $ | 556,976 | | $ | 198,920 | |
Interest payments on long-term debt(1) | | 377,701 | | 85,337 | | 170,673 | | 71,961 | | 49,730 | |
Credit facility | | 43,500 | | 43,500 | | — | | — | | — | |
Operating lease obligations | | 113,136 | | 18,300 | | 28,202 | | 20,589 | | 46,045 | |
Total contractual obligations | | $ | 1,290,233 | | $ | 147,137 | | $ | 198,875 | | $ | 649,526 | | $ | 297,695 | |
(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 December 31, 2010 of U.S.$1.0054 to $1.00.
As at December 31, 2010, we have accrued liabilities for obligations with respect to our pension plans, asset retirement obligations and remediation totalling $3.2 million, $9.6 million and $12.4 million, respectively, but the timing of such payments is uncertain due to the estimates used to calculate these amounts and the long term nature of these balances. In addition, we have a management agreement with Riverstone, whereby we are required to pay an annual fee as consideration for their performance of advisory, consulting and other services. The management fee payable is the lesser of one percent of our EBITDA for the year or $1.0 million.
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 NGL prices, (ii) interest rates and (iii) currency exchange rates. We utilize various derivative instruments to manage commodity price and currency rate exposure and, in certain circumstances, to realize incremental margin during volatile market conditions. Our commodity trading and risk management policies and procedures are designed to establish and manage to an approved level of Value at Risk. We have a Risk Management Committee that has direct responsibility and authority for our risk policies and our trading controls and procedures and certain aspects of corporate risk management. Our approved strategies are intended to mitigate risks that are inherent in our core businesses of gathering and marketing and storage. To hedge the risks discussed above we engage in risk management activities that we categorize by the risks we are hedging and by the physical product that is creating the risk. The following discussion addresses each category of risk.
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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 December 31, 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 $6.0 million and $3.3 million for the year ended December 31, 2010 and the year ended December 31, 2009, respectively. A 15% unfavorable change would decrease our net income by $6.0 million and $3.3 million for the year ended December 31, 2010 and the year ended December 31, 2009, respectively. However, these changes may be offset by the use of one or more commonplace risk management strategies.
Electricity Price Risk. We hedged our exposure to electricity price fluctuations by entering into a financial swap contract to fix the level of anticipated electricity costs that are price sensitive to the Alberta Electric System Operator (AESO) Pool Price. If the actual AESO Pool Price is greater than the bought fixed price per megawatt hour, we receive the difference between that price and the bought fixed price per megawatt hour. If the actual AESO Pool Price is less than the bought fixed price per megawatt hour, we pay the difference between that price and the bought fixed price per megawatt hour. A 10% favorable change would increase our net income by $0.2 million as of December 31, 2010, and by $0.3 million as of December 31, 2009. A 10% unfavorable change would decrease our net income by $0.2 million as of December 31, 2010, and by $0.3 million as of December 31, 2009.
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. For the period from December 13 to December 31, 2008, the increase or decrease in net income for a 100 basis point change in interest rates on the long-term debt would amount to $0.2 million. For the period January 1, to May 27, 2009, the increase or decrease in net income for a 100 basis point change in interest rates on the long-term debt would amount to $1.9 million. However, the First Lien Notes accrue interest at a fixed rate of 11.75% per annum. In addition, our Senior Notes issued on January 19, 2010 accrue interest at a fixed rate of 10.0% per annum.
Under our Credit facility, we are subject to interest rate risk, as borrowings bear interest at a rate equal to, at our 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 year ended December 31, 2009, the impact on net income for a 100 basis point change in interest rates on the outstanding amount under our Credit facility would not have been material.
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Currency exchange risks. Our assets and liabilities in foreign currencies are translated at the period-end rate. Exchange differences arising from this translation are recorded in our statement of operations. In addition, currency exposures can arise from revenues and purchase transactions denominated in foreign currencies. Generally, transactional currency exposures are naturally hedged (i.e., revenues and expenses are approximately matched), but where appropriate, are covered using forward exchange contracts. All of the foreign currency forward exchange contracts entered into by us, although effective hedges from an economic perspective have not been designated as hedges for accounting purposes, and therefore any gains and losses on such forward exchange contracts impact our earnings. Additionally, currency exposure occurs on the principal of our long-term debt and the related interest payments, as they are both denominated in U.S. dollars. To date we have not entered into any hedges on the principal of our long-term debt but we have entered into forward exchange option contracts and U.S. dollar forward contracts on our U.S. dollar interest payments.
A 5% unfavorable change in the value of the Canadian dollar relative to the U.S. dollar would decrease our net income by $1.4 million and $1.0 million for the year ended December 31, 2010 and for the year ended December 31, 2009, respectively. A corresponding favorable change would increase our net income by $1.4 million and $1.0 million for the year ended December 31, 2010 and for the year ended December 31, 2009, respectively. We expect to continue to enter into financial derivatives, primarily forward contracts, to reduce foreign exchange volatility. We are exposed to credit loss in the event of non-performance by the other party to the derivative financial instruments. We mitigate this risk by entering into agreements directly with a number of major financial institutions that meet our credit standards and that we expect to fully satisfy their contractual obligations. We view derivative financial instruments purely as a risk management tool and, therefore, do not use them for speculative trading purposes.
As of December 31, 2010 and 2009, we had outstanding U.S. dollar denominated long-term debt of U.S.$760.0 million and U.S.$560.0 million, respectively. 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 $32.5 million and $25.1 million for the year ended December 31, 2010 and for the year ended December 31, 2009, respectively. A corresponding favorable change would increase our net income by $32.5 million and $25.1 million for the year ended December 31, 2010 and for the year ended December 31, 2009, respectively. Our long-term debt accrues interest at fixed interest rates or U.S.$85.8 million per annum. Excluding the impact of any forward exchange options, a 5% unfavorable change in the value of the Canadian dollar relative to the U.S. dollar as of December 31, 2010 would increase our annual interest expense by $4.3 million. A 5% favorable change in the value of the Canadian dollar relative to the U.S. dollar as of December 31, 2010 would decrease our annual interest expense by $4.3 million.
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Item 6. Directors, Senior Management and Employees
6.A. DIRECTORS AND SENIOR MANAGEMENT
The following table provides information regarding executive officers and directors:
Name | | Age | | Position |
| | | | |
A. Stewart Hanlon | | 51 | | Director, President and Chief Executive Officer |
| | | | |
Richard G. Taylor | | 58 | | Director, Executive Vice President Finance and Chief Financial Officer |
| | | | |
Rodney J. Bantle | | 54 | | Senior Vice President Truck Transportation (Gibson Energy ULC only) |
| | | | |
Donald A. Fowlis | | 50 | | Senior Vice President Finance |
| | | | |
Samuel van Aken | | 47 | | Senior Vice President Propane Marketing & Distribution (Gibson Energy ULC only) |
| | | | |
Douglas P. Wilkins | | 47 | | Senior Vice President Marketing, Supply and Trading (Gibson Energy ULC only) |
| | | | |
Richard M. Wise | | 50 | | Senior Vice President Operations (Gibson Energy ULC only) |
| | | | |
H. Leslie Carmichael | | 57 | | Chief Executive Officer of Taylor Companies, LLC |
| | | | |
Clayton H. Woitas | | 61 | | Director |
| | | | |
Andrew W. Ward | | 44 | | Director and Chairman of the Board of Directors |
| | | | |
Robert M. Tichio | | 33 | | Director |
A. Stewart Hanlon joined Gibson in April 1991 as Controller of Canwest Propane and in his 20-year tenure with Gibson has filled senior roles in finance, business development and operations culminating in his role as Executive Vice President and Chief Operating Officer, a position he held from 2007 to April of 2009, when he was appointed President and Chief Executive Officer. Mr. Hanlon was named as a member of the Board of Directors of Gibson Energy ULC in October 2008, Gibson Energy Holding ULC in December 2008 and GEP Midstream Finance Corp. in January 2010. Mr. Hanlon also serves on the board of directors of Palko. Mr. Hanlon holds a Bachelor of Commerce degree (Finance and Accounting) from the University of Saskatchewan, is a Chartered Accountant and was admitted to the ICAS (Saskatchewan) in 1989 and ICAA (Alberta) in 1990.
Richard G. Taylor joined Gibson in May 1991 as General Manager, Financial Projects, was promoted to Vice President Finance in 1994 and was appointed to the role of Executive Vice President Finance and Chief Financial Officer in October 2005. In August 1995, Mr. Taylor was appointed to the Board of Directors and assumed responsibility as Corporate Secretary for Gibson until December 2008. Mr. Taylor was appointed to the role of Executive Vice President Finance and Chief Financial Officer and named as a member of the Board of Directors of Gibson Energy Holding ULC and GEP Midstream Finance Corp. in January 2010. Mr. Taylor holds a Bachelor of Commerce degree from the University of Calgary, and is a Chartered Accountant and a Chartered Business Valuator.
Rodney J. Bantle joined Gibson in 1996 as Manager of Business Development, Truck Transportation, and held various management positions prior to becoming Vice President Truck Transportation in March 2007 and Senior Vice President of Truck Transportation in April 2009. Prior to joining Gibson, Mr. Bantle was Marketing Manager of Tirecraft Auto Centers Ltd. Mr. Bantle holds a Bachelor of Commerce degree from the University of Alberta.
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Donald A. Fowlis joined Gibson in October 1993 as Corporate Controller, was promoted to the position of Vice President Finance in October 2005 and was promoted to his current position of Senior Vice President Finance in April 2009. Mr. Fowlis was appointed to the role of Senior Vice President Finance of Gibson Energy Holding ULC and GEP Midstream Finance Corp. in January 2010. Prior to joining Gibson, Mr. Fowlis spent nine years with a major accounting firm. Mr. Fowlis holds a Bachelor of Commerce degree from the University of Alberta, is a Chartered Accountant and was admitted to the ICAA (Alberta) in 1988.
Samuel van Aken joined Gibson in 1992 as a Manager of Canwest Propane. He has held various roles within the Company’s propane and NGL marketing and distribution segment. He is currently Senior Vice President Propane Marketing & Distribution, a role he has held since April 2009. In this role, Mr. van Aken is responsible for propane and NGL marketing and operations of the Company. Mr. van Aken has over 25 years of experience in the fuel distribution and marketing business.
Douglas P. Wilkins joined Gibson in April 2009 as Senior Vice President Marketing, Supply and Trading. Mr. Wilkins gained two decades of marketing, supply and trading experience at senior levels in the oil and gas industry in western Canada. Prior to joining Gibson, Mr. Wilkins was the President of Tidal Energy Marketing, Inc., a position he held from 2002. Mr. Wilkins graduated with a Bachelor of Commerce degree from the University of Calgary in 1985.
Richard M. Wise joined Gibson in October 2009 as Senior Vice President Operations. Mr. Wise brings 26 years of complimentary midstream experience to Gibson. Prior to joining Gibson, Mr. Wise spent the last six years with CCS Corporation as Vice President Engineering, Regulatory and Midstream Development. Mr. Wise also serves on the board of directors of Palko. Mr. Wise graduated with a Bachelor of Science degree in Chemical Engineering from the University of Calgary in 1985 and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta.
H. Leslie Carmichael joined Gibson in May 2010 as part of the acquisition of Taylor as Chief Executive Officer of Taylor Companies LLC. Mr. Carmichael joined Taylor Companies, LLC in October 2007 as Chief Executive Officer. Mr. Carmichael has over 37 years of experience in the transportation and logistics industry and has held senior management positions at Swift Transportation Corporation and M.S. Carriers Inc.
Clayton H. Woitas has served as a director of Gibson Energy ULC, Gibson Energy Holding ULC and GEP Midstream Finance Corp. since June 2010. Mr. Woitas is Chairman and Chief Executive Officer of Range Royalty Management Ltd. He is a director of Encana Corporation, NuVista Energy Ltd. and Enerplus Resources Fund. He is also a director of several private energy-related companies and advisory boards. Mr. Woitas was founder, Chairman, and President and Chief Executive Officer of privately held Profico Energy Management Ltd. from January 2000 to June 2006. Prior to April 2000, he was a director and President and Chief Executive Officer of Renaissance Energy Ltd. He holds a Bachelor of Science in Civil Engineering from the University of Alberta.
Andrew W. Ward has served as a director of Gibson Energy ULC since the Acquisition in December 2008 and has served as a director of GEP Midstream Finance Corp. and Gibson Energy Holding ULC since September 2008. Mr. Ward is currently a Managing Director of Riverstone Holdings LLC, where he has been since 2002. Prior to joining Riverstone, Mr. Ward was a Limited Partner and Managing Director of Hyperion Partners/Ranieri & Co. Mr. Ward currently serves on the board of directors of Niska Gas Storage, Mistral Energy and USA Compression. Mr. Ward received his A.B. from Dartmouth College and his M.B.A from the UCLA Anderson School of Management.
Robert M. Tichio has served as a director of Gibson Energy ULC since December 2008 and as a director of Gibson Energy Holding ULC and GEP Midstream Finance Corp. since September 2008. Mr. Tichio has served as Chairman of the Board of Directors of GEP Midstream Finance Corp. since January 2010 and from September 2008 until January 2010 he served as President and Secretary of GEP Midstream Finance Corp. Mr. Tichio currently serves as a Principal of Riverstone Holdings LLC, where he has been since 2006. Prior to joining Riverstone, Mr. Tichio was in the Principal Investment Area of Goldman Sachs, and began his career at JP Morgan, in the Mergers & Acquisitions group. Mr. Tichio currently serves on the boards of directors of CanEra Resources; Titan Operating; Eagle Energy of Oklahoma; Phoenix Exploration; Three Rivers Operating Company; Mistral Energy; and ILX Holdings. Mr. Tichio received his A.B. from Dartmouth College and his M.B.A. from Harvard Business School.
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6.B. COMPENSATION
Our Director and Executive Compensation
Director Compensation
During the fiscal year ended December 31, 2010, we paid no compensation to our non-executive directors. All directors are entitled to be reimbursed for travel and other expenses properly incurred in attending meetings of the board or of any committee of the board. The directors of Gibson Energy ULC also serve as directors of Gibson Energy Holding ULC and GEP Midstream Finance Corp. They do not receive any remuneration from us for acting in those capacities.
Senior Management Compensation
We are not currently required to publicly disclose individual compensation information under our governing statute or under any securities legislation. As a result, we do not publicly disclose individual compensation information in Canada. The aggregate salary and benefits paid by us to our senior management in the year ended December 31, 2010, was $6.7 million. The aggregate salary and benefits paid by us to our five highest-paid officers for the fiscal year ended December 31, 2010 was $4.8 million.
The aggregate salary and benefits include payments under our annual bonus program, in which all members of senior management participate. The annual bonus program is based on our financial performance as well as an individual discretionary portion based on non-financial measures and on each individual’s performance. Bonus calculations were made based on the board-approved budget, as determined by our financial results and recommendations for the executives that were approved by the Compensation Committee of the Board of Directors.
The aggregate salaries and benefits also includes expense incurred for awards issued pursuant to our Equity Incentive Plan (the “Plan”). The Plan provides for the issuance of stock options, stock appreciation rights, restricted stock and restricted stock units of Gibson Energy Holding ULC to employees, directors, consultants and other associates of the Company. The options are to purchase shares of Gibson Energy Holding ULC and generally vest in equal tranches annually over a period of four to five years from the date of grant and have a maximum term of ten years. We have granted both time-vesting stock options and performance vesting stock options under the Plan. The performance vesting options vest and expire under the same terms and service conditions as the time-vesting options, with vesting subject to attaining prescribed performance relative to predetermined financial measures. In the year ended December 31, 2010, an aggregate of 2,000 options were granted to our senior management. However, no options were granted to our five highest paid officers in the year ended December 31, 2010. In the year ended December 31, 2010, we recorded stock based compensation expense of $2.5 million and $1.7 million for our senior management and the five highest-paid officers, respectively, using an option-pricing model based on the Black-Scholes model.
The total amounts set aside or accrued by us in the year ended December 31, 2010 to provide pension, retirement or similar benefits to senior management amounted to $0.7 million and $0.5 million with respect to the five highest-paid officers. These include standard pension, retirement or similar benefits as provided by us to all of our employees under our employee benefit programs, as well as additional pension benefits accruing to senior management and the five highest paid officers under the terms of the Supplemental Non-Registered Savings Plan we put in place effective April 1, 2009 to replace the Supplemental Executive Retirement Plan that had been in place when we were owned by Hunting, which Plan was terminated.
Directors’ and Officers’ Liability Insurance; Indemnity Payments
We have acquired and maintain liability insurance for our directors and officers, as well as those of our subsidiaries. The total coverage limit of our current insurance is $30.0 million per claim and $30.0 million in the annual aggregate. The annual premium for such coverage is $58,280, with coverage in place through November 30, 2011. Claims for which we grant
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indemnification to insured persons are subject to a $100,000 deductible for any one claim. There have been no claims made or paid under this insurance to date.
Employment Agreements
Certain of our executive officers have employment agreements in place. Under these agreements, each of the executive officers is employed on an at-will basis. We may terminate the employment of each executive officer for “cause,” at any time, without notice or remuneration, for certain acts of the officer. Each of the executive officers may also terminate his or her employment for “good reason” upon certain events occurring within one year following a change in control. Furthermore, either party may terminate employment at any time without cause upon advance written notice to the other party. If we terminate the executive officer’s employment other than for cause, death or disability, or if the executive officer terminates employment for “good reason” within one year following a change in control, the executive officer will be entitled to a severance payment equal to a certain multiple of his or her annual compensation (ranging from between one and two times depending on the executive officer’s position), a multiple of the average bonus paid during the past two years and certain other benefits. Moreover, certain executive officers with lower initial multiples of severance will be entitled to an additional multiple of his or her annual compensation, depending on the years of his or her employment with us, not to exceed 1.5 times annual compensation.
Each executive officer has agreed to hold, both during and after the employment agreement is terminated, in strict confidence and not to use, except as required in the performance of his duties in connection with the employment, any confidential information, technical data, trade secrets and know-how of our company or the confidential information of any third party, including our affiliated entities and our subsidiaries, received by us. In addition, the executive officers are subject to a non-solicitation provision.
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6.C. BOARD PRACTICES
Board of Directors
The Board of Directors of the Company currently consists of five members. Each director is elected annually, and we expect that such directors will serve until their successors are appointed or until they resign, or their office is earlier vacated in accordance with the by-laws of the corporation or with the provisions of the Business Corporations Act (Alberta). Each of the directors has served in his respective capacity since his election. See “Directors and Senior Management” for the period during which each director and member of senior management has served in that office.
Directors’ Service Contracts
There are no director service contracts between the Company and its non-executive directors providing for benefits upon termination of employment.
Committees of the Board
The Board of Directors has an Audit Committee and a Compensation Committee.
Audit Committee
The Audit Committee is comprised of Messrs. Tichio, Hanlon and Ward.
The principal duties and responsibilities of the Audit Committee, which has the authority to engage outside counsel and other outside advisors as it deems appropriate to assist it in the performance of its functions, are to assist the board in its oversight of:
· the integrity of the Company’s financial statements and related information;
· the Company’s compliance with applicable legal and regulatory requirements;
· the independence, qualifications and appointment of the Company’s auditor; and
· management responsibility for reporting on internal controls and risk management.
Our Audit Committee is also responsible for:
· compensating and overseeing the work of the Company’s accounting firm;
· establishing procedures for (a) the receipt, retention and treatment of complaints received by the Company regarding accounting, internal controls or auditing matters and (b) confidential, anonymous submission of complaints by employees regarding questionable accounting or auditing matters; and
· reviewing and discussing the annual consolidated financial statements with management.
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Compensation Committee
The Compensation Committee is comprised of Messrs. Tichio and Ward.
The principal duties and responsibilities of the Compensation Committee are to assist the board in its oversight of:
· the compensation, nomination, evaluation and succession of officers and other management personnel; and
· determining the directors’ remuneration for board and committee service.
6.D. EMPLOYEES
As of December 31, 2010, we had approximately 1,039 employees, including 971 full-time employees, 16 part-time employees and 52 fixed term employees. Our fixed term employees are employees of Gibson for a defined fixed term, which is typically one year or less. Of the total employees, 100 are employed in the United States with the remainder employed in Canada. As of December 31, 2010, 41 employees are union employees and are party to the collective agreement between Moose Jaw Refinery Partnership and the Communications, Energy & Paperworkers Union of Canada, Local 595, which expires on January 31, 2013. In addition, 49 employees are party to the Gibson Energy Partnership and Gibson Employees’ Association collective agreement, which expires on December 31, 2013. The following table shows a breakdown of our employees by business segment:
Business segment | | Employees as of
December 31,
2010 | |
Terminals and pipelines | | 119 | |
Truck transportation | | 429 | |
Propane and NGL marketing and distribution | | 235 | |
Processing and wellsite fluids | | 76 | |
Marketing | | 19 | |
Segment total | | 878 | |
Finance and administrative | | 146 | |
Executive | | 15 | |
Total | | 1,039 | |
6.E. SHARE OWNERSHIP
The aggregate share ownership of the members of the board of directors and our senior management is 0% of the shares in Gibson Energy Holding ULC.
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Item 7. Major Shareholders and Related Party Transactions
7.A. MAJOR SHAREHOLDERS
Gibson Energy ULC is a direct, wholly owned subsidiary of Gibson Energy Holding ULC and GEP Midstream Finance Corp. is a direct, wholly owned subsidiary of Gibson Energy ULC. Gibson Energy Holding ULC is an unlimited liability corporation organized under the laws of Alberta, all of the outstanding common shares of which are owned by R/C Guitar Coöperatief U.A., which is a cooperative entity organized under the laws of The Netherlands. 1441682 Alberta Ltd., a wholly owned subsidiary of Co-op, owns 100,000 preferred shares of Gibson Energy Holding ULC. All of the shares of R/C Guitar Coöperatief U.A. are owned, directly or indirectly, by Riverstone.
7.B. RELATED PARTY TRANSACTIONS
Management Agreement
We entered into a management agreement with an affiliate of Riverstone, Riverstone Equity Partners, L.P., at the closing of the Acquisition, pursuant to which we pay Riverstone a fee for management and financial advisory services and oversight to be provided to us and our subsidiaries. Pursuant to this agreement, subject to certain conditions, we will pay an annual management fee to Riverstone of the lesser of one percent of the Company’s EBITDA for that year, or $1.0 million dollars. We also reimburse Riverstone’s out-of-pocket expenses, and we may pay Riverstone additional fees associated with financial advisory services and other future transaction services. Riverstone also received a one-time transaction fee of U.S.$12.0 million upon consummation of the Acquisition.
Employment Agreements
Certain of our executive officers have employment agreements in place. For a discussion of the terms of those agreements, see Item 6B. “Compensation—Employment Agreements.”
Shareholders Agreement
In connection with the Acquisition, Co-op, 1441682 Alberta Ltd. and Gibson Energy Holding ULC entered into a Unanimous Shareholders Agreement (the “Shareholders Agreement”). Under the Shareholders Agreement, 1441682 Alberta Ltd. has the right to appoint a representative as an observer to the board of directors of Gibson Energy Holding ULC. 1441682 Alberta Ltd. is also entitled to receive certain financial information about Gibson Energy Holding ULC and Gibson Energy Holding ULC must obtain the consent of 1441682 Alberta Ltd. in connection with certain actions, including redemptions of outstanding securities held by Co-op and, subject to certain exceptions, any agreement or transaction between Gibson Energy Holding ULC and its subsidiaries, on the one hand, and Co-op or its affiliates, on the other hand. At any time during which Hunting holds the warrant for common shares of 1441682 Alberta Ltd., issued in connection with the Acquisition, Gibson Energy Holding ULC may not sell or issue to any person any equity securities that rank senior to either the preferred shares of Gibson Energy Holding ULC held by 1441682 Alberta Ltd., or Gibson Energy Holding ULC’s Class B Common Shares, without the consent of 1441682 Alberta Ltd. The Shareholders Agreement also contains drag-along and equity purchase rights with respect to shares of Gibson Energy Holding ULC. In connection with the Shareholders Agreement, Hunting, Co-op and 1441682 Alberta Ltd. also entered into a memorandum of agreement, under the terms of which Hunting has the right to direct the actions of 1441682 Alberta Ltd. in connection with the rights granted to them under the Shareholders Agreement.
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Transactions with Certain Related Parties
A. Stewart Hanlon, our President and Chief Executive Officer, is a member of the Board of Directors of the Anluan Foundation, a foundation benefiting the University of Saskatchewan. In the year ended December 31, 2010, the Anluan Foundation purchased approximately $2.0 million of our Senior Notes as an investment.
A. Stewart Hanlon, our President and Chief Executive Officer and Rick Wise, our Senior Vice President, Operations, both began serving as members of the board of directors of Palko in October 2009. On December 15, 2009, we acquired an equity interest of approximately 39% in Palko for $6.6 million and on June 30, 2010, we participated in a private placement in Palko for $3.1 million, which allowed us to maintain out approximate 39% equity interest. On February 1, 2010, we entered into a marketing and transportation services agreement with Palko. For the years ended December 31, 2010 and 2009, we recorded sales to Palko of $0.2 million and $30,000, respectively. In the years ended December 31, 2010 and 2009, we purchased product from Palko of $3.5 million and $1.7 million, respectively. We had no material transactions with Palko in the year ended December 31, 2008.
For the year ended December 31, 2010, we recorded sales of $4.5 million to and purchased product of $25.4 million from Northern Blizzard Resources Inc., a portfolio company of Riverstone. We had no transactions with Northern Blizzard Resources Inc. in the years ended December 31, 2009 and 2008.
For the years ended December 31, 2010, 2009 and 2008, we purchased product of $0.1 million, $0.1 million and $0.2 million, respectively, from Kinder Morgan, Inc., a portfolio company of Riverstone.
7.C. INTERESTS OF EXPERTS AND COUNSEL
Not Applicable
Item 8. Financial Information
8.A. CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION
See “Item 17. Financial Statements” for our financial statements, related notes and other financial information filed with this annual report on Form 20-F.
8.B. SIGNIFICANT CHANGES
Except as otherwise disclosed in this Form 20-F, there have been no material changes in our financial position, operations or cash flows since December 31, 2010.
Item 9. The Offer and Listing
9.A. OFFER AND LISTING DETAILS
Not Applicable
9.B. PLAN OF DISTRIBUTION
Not Applicable
9.C. MARKETS
Not Applicable
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9.D. SELLING SHAREHOLDERS
Not Applicable
9.E. DILUTION
Not Applicable
9.F. EXPENSES OF THE ISSUE
Not Applicable
Item 10. Additional Information
10.A. SHARE CAPITAL
Not Applicable
10.B. MEMORANDUM AND ARTICLES OF ASSOCIATION
REGISTOR
Gibson Energy ULC was amalgamated under the provisions of the Business Corporations Act (Alberta) (the “Act”) on January 1, 2010, with a corporation number of 2015092279.
ARTICLES AND BY-LAWS
The following brief description of provisions of the Act, our Articles and General By-Law No. 2 (“By-Laws”) does not purport to be complete and is subject in all respects to the provisions of the Act and our Articles and By-Laws.
Conflicts of Interest
Our By-Laws provide that a director or officer of the Corporation who is a party to a material contract or proposed material contract with us, or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with us shall disclose the nature and extent of his interest at the time and in the manner provided in the Act. Except as provided in the Act, no such director shall vote on any resolution to approve such contract. If a material contract is made between us and one or more of its directors or officers, or between us and another person of which a director or officer of the Corporation is a director or officer or in which the director or officer has a material interest, (i) the contract is neither void nor voidable by reason only of that relationship, or by reason only that a director with an interest in the contract is present at or is counted to determine the presence of a quorum at a meeting of directors or committee of directors that authorized the contract, and (ii) a director or officer or former director or officer to whom a profit accrues as a result of the making of the contract is not liable to account to us for that profit by reason only of holding office as a director or officer, if the director or officer disclosed his interest in accordance with the provisions of the Act and the contract was approved by the directors or the shareholders and it was reasonable and fair at the time it was approved.
Borrowing Powers
Our By-Laws provide that the directors may from time to time: (a) borrow money on the credit of the Corporation; (b) issue, reissue, sell or pledge debt obligations of the Corporation, including without limitation, bonds, debentures, notes or other evidences of indebtedness or guarantee of the Corporation, whether secured or unsecured; (c) give a guarantee on behalf of
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the Corporation to secure performance of an obligation of any individual, partnership, association, body corporate, trustee, executor, administrator or legal representative; (d) mortgage, hypothecate, pledge or otherwise create an interest in or charge on all or any property of the Corporation, owned or subsequently acquired, to secure payment of a debt or performance of any other obligation of the Corporation.
Shareholders’ Meetings
Gibson Energy Holding ULC currently owns all of our equity. Our By-Laws provide that a resolution in writing signed by all the shareholders or signed counterparts of such resolution by all the shareholders entitled to vote on that resolution at a meeting of shareholders is as valid as if it had been passed at a meeting of the shareholders duly called, constituted and held.
Our By-Laws provide that, subject to the Act, an annual meeting of shareholders shall be held on such day and at such time in each year as the Board of Directors may from time to time determine, for the purpose of considering the financial statements and reports required by the Act to be placed before the annual meeting, electing directors, appointing auditors and for the transaction of such other business as may properly be brought before the meeting. The Act requires that, subject to certain exceptions, the directors must call a special meeting of shareholders upon the requisition of at least ten percent of our issued shares entitled to vote at the meeting being requisitioned.
The Act provides that for purposes of determining shareholders entitled to receive notice of a meeting of shareholders, the directors may fix a record date in advance so long as the date is not more than 50 or less than 21 days before the date of the meeting. Where no record date is fixed, the record date is the close of business on the day immediately preceding the day notice is given or the day of the meeting itself if no notice is given. The Act and our By-Laws provide that notice of the time and place of each shareholder meeting shall be sent not less than 21 nor more than 50 days before the meeting to (i) each shareholder entitled to vote, (ii) each director, and (iii) our auditor. If special business is to be transacted, the notice must state or be accompanied by a statement of the nature of that business in sufficient detail to permit the shareholder to form a reasoned judgment on the proposal. All business transacted at a special meeting of shareholders and all business transacted at an annual shareholder meeting, except consideration of the financial statements and auditor’s report, election of directors and reappointment of the auditor constitutes special business.
Our By-Laws provide that a quorum for the transaction of business at any meeting of shareholders shall be met if two persons are present with each holding or representing by proxy at least one (1) issued share.
Our By-laws also state that the only persons entitled to be present at a meeting of shareholders shall be those persons entitled to vote thereat, the directors and our auditors and others who, although not entitled to vote, are entitled or required under any provision of the Act or our Articles or By-Laws to be present at the meeting. Any other person may be admitted only on the invitation of the Chairman of the meeting or with the consent of the meeting.
Authorized and Issued Capital
We are authorized to issue an unlimited number of Common Shares with 637,656 shares issued and outstanding.
Common Shares
Each Common Share has one vote with the holders of the Common Shares entitled to attend and vote at all meetings of shareholders. In addition, the holders of the Common Shares are entitled to receive any dividends that may be declared by the Board of Directors on the Common Shares. However, the directors shall not declare and the Corporation shall not pay a dividend if there are reasonable grounds for believing that (a) the Corporation is, or would be after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of the Corporation’s assets would thereby be less than the aggregate of its liabilities and the stated capital of all classes.
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Number of Directors; Filling Vacancies
Our Articles provide that the number of directors comprising the entire Board is a minimum of one and a maximum of seven. We currently have a fixed number of five directors. All of our directors have been elected to serve until the next annual meeting or until their successor is elected or appointed.
Under the Act and provided that a quorum of directors remains in office, vacancies may be filled by the directors. If less than a quorum of directors remain in office, or if there has been a failure to elect the required fixed number of directors, any vacancy must be filled by the shareholders and the directors are required to call a special meeting of the shareholders to fill the vacancy. No person is required to hold any equity of the Corporation to qualify as a director.
10.C. MATERIAL CONTRACTS
The following is a summary of each material contract, other than contracts entered into in the ordinary course of business, to which we are a party:
On May 27, 2009, we issued the First Lien Notes, which have an original term of five years expiring on May 27, 2014, and accrue interest at 11.75% per annum, payable semi-annually on June 1 and December 1 of each year. Throughout the term of the First Lien Notes and under certain conditions, we have the option to prepay the principal on the First Lien Notes. Any prepayments made up to May 31, 2013 would be at a premium. All borrowings under the First Lien Notes are collateralized by substantially all of our property, plant and equipment and all equity interests.
On January 19, 2010, we issued the Senior Notes, which have an original term of eight years expiring on January 15, 2018, and accrue interest at 10.0% per annum payable semi-annually on July 15 and January 15 of each year. Throughout the term of the Senior Notes and under certain conditions, we have the option to prepay the principal on the Senior Notes. Any prepayment made up to January 14, 2017 would be at a premium.
The First Lien Notes and the Senior Notes are guaranteed by all of our existing restricted subsidiaries.
We have a Credit facility of up to U.S.$200.0 million, of which up to U.S.$30.0 million is for use by subsidiaries with collateral assets located in the United States. The proceeds of the Credit facility are available to provide financing for working capital and other general corporate purposes. The Credit facility has a term of four years expiring on December 12, 2012. Borrowings under the Credit facility bear interest at a rate equal to either LIBOR, the lenders prime rate, the Bankers Acceptance rate or the Above Bank Rate, plus an applicable margin based on a pricing grid. Any borrowings under the Credit facility are secured by our current assets, including, but not limited to, inventory and accounts receivable. The term of our Credit facility requires us to maintain a “Fixed Charge Coverage Ratio” of not less than 1.1:1, following any period of 3 consecutive days in which availability is less than an amount equal to 15% of the commitments by the lenders under the Credit facility. As of December 31, 2010, we had $43.5 million drawn and issued letters of credit of $59.2 million against the facility, and therefore 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 Credit facility. An event of default resulting from a breach of a financial covenant may result, at the option of lenders holding a majority of the loans, in an acceleration of repayment of the principal and interest outstanding and a termination of the Credit facility, and could result in an acceleration of amounts due and payable under the Notes. In addition, the facility contains a provision that requires prior written consent for acquisitions exceeding annual consideration of U.S.$80.0 million, exclusive of acquisitions funded by permitted equity or debt raised to finance such transactions.
The Notes and the Credit facility also contain non-financial covenants that restrict some of our activities, including our ability to dispose of assets, incur additional debt, pay dividends, create liens, make investments and engage in specified transactions with affiliates. The Notes and the Credit facility also contain customary events of default, including defaults based on events of bankruptcy and insolvency, non-payment of principal, interest or fees when due, subject to specified grace periods, breach of specified covenants, change in control and material inaccuracy of representations and warranties. As of December 31,
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2010, we were in compliance with all of our non-financial covenants under our First Lien Notes, Senior Notes and Credit facility.
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10.D. EXCHANGE CONTROLS
There are no governmental laws, decrees or regulations in Canada relating to restrictions on the export or import of capital, or Canadian exchange restrictions affecting the remittance of dividends, interest, royalties or similar payments to non-resident holders of our securities.
10.E. TAXATION
Not Applicable
10.F. DIVDENDS AND PAYING AGENTS
Not Applicable
10.G. STATEMENT BY EXPERTS
Not Applicable
10.H. DOCUMENTS ON DISPLAY
We file periodic reports and other information with the SEC. These reports include certain financial and statistical information about us and may be accompanied by exhibits. You may read and copy this information at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549, or obtain copies of this information by mail from the public reference room at the prescribed rates. You may call the SEC at 1-800-SEC-0330 for further information on the SEC’s Public Reference Room. The SEC also maintains an Internet website that contains reports and other information about companies like us who file electronically with the SEC. The URL of that website is http://www.sec.gov.
10.I. SUBSIDIARY INFORMATION
Not Applicable
Item 11. Quantitative and Qualitative Disclosures about Market Risk
See “Item 5—Operating and Financial Review and Prospects” and Note 20 to our annual audited consolidated financial statements contained in this Form 20-F for quantitative and qualitative disclosure of market risk.
Item 12. Description of Securities Other than Equity Securities
12.A. DEBT SECURITIES
Not Applicable
12.B. WARRANTS AND RIGHTS
Not Applicable
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12.C. OTHER SECURITIES
Not Applicable
12.D. AMERICAN DEPOSITORY SHARES
Not Applicable
PART II
Item 13. Defaults, Dividend Arrearages and Delinquencies
Not Applicable
Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
Not Applicable.
Item 15. Controls and Procedures
(a) Disclosure Controls and Procedures
Based on our management’s evaluation (with the participation of our principal executive officer and principal financial officer), as of December 31, 2010, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
(b) Management’s Annual Report on Internal Control over Financial Reporting
This Form 20-F does not include a report of management’s assessment regarding internal control over financial reporting due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.
(c) Attestation Report of the Registered Public Accounting Firm
This Form 20-F does not include an attestation report of the Company’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies.
(d) Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the period covered by this Form 20-F that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Item 16A. Audit Committee Financial Expert
Our Board of Directors has determined that Mr. Tichio is an “audit committee financial expert” (as defined in Item 16A of Form 20-F) serving on our Audit Committee. Based upon the listing standards of the NYSE, we believe that Mr. Tichio is not considered independent as that term is defined in the NYSE listing standards.
Item 16B. Code of Ethics
We have adopted a code of conduct and ethics that applies to our directors, officers, employees and contractors. A copy of our code of conduct and ethics is available upon request, without charge, by contacting T. Murray Carey, Vice President General Counsel and Secretary at 1700, 440-2nd Avenue, S.W. Calgary, Alberta, Canada, T2P 5E9.
Item 16C. Principal Accountant Fees and Services
The following fees were billed to us by PricewaterhouseCoopers LLP and approved by the Board of Directors during the prior two years (in thousands):
| | Year ended December 31, | |
| | 2010 | | 2009 | |
| | | | | |
Audit fees | | $ | 620 | | $ | 602 | |
Audit-related fees | | 207 | | 99 | |
Tax fees | | 306 | | 99 | |
All other fees | | 444 | | 546 | |
Total fees | | $ | 1,577 | | $ | 1,346 | |
Audit fees include fees for the audit of our consolidated financial statements and the review of our quarterly reports.
Audit-related fees include fees for services that are related to the audit of the consolidated financial statements. These services include assistance with the consultation with respect to IFRS and consultation on accounting and disclosure matters.
Tax fees include fees for the preparation of income tax returns and advice on tax-related matters.
All other fees include fees for professional services related to the issuances of our Notes and professional services related to the filing of our Registration Statements, audit of pension plans, due diligence on acquisitions and an annual subscription to accounting research software.
Our Board of Directors approves, on the recommendation of the Audit Committee, all fees paid to the external auditors. In addition, in accordance with applicable rules regarding audit committees, the Audit Committee reviews and approves, in advance, the scope and related fees for all non-audit services which are to be provided by the external auditors. In considering whether to approve non-audit services, the Audit Committee considers whether the provision of these non-audit services may impact the objectivity and independence of the external auditor and, in respect of non-audit services provided by PricewaterhouseCoopers LLP in 2010, the Audit Committee has concluded that it does not.
Item 16D. Exemptions from the Listing Standard for Audit Committees
Not Applicable
Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Not Applicable
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Item 16F. Change of Registrant’s Certifying Accountant
Not Applicable
Item 16G. Corporate Governance
Not Applicable
PART III
Item 17. Financial Statements
Our audited consolidated financial statements for the year ending December 31, 2010, including the notes thereto and together with auditor’s report thereon, are included in this Form 20-F beginning on page F-1.
Item 18. Financial Statements
Not Applicable
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Item 19. Exhibits
1.1# | | Certificate and Articles of Amalgamation of the Issuer, dated as of January 1, 2010 |
| | |
1.2# | | By-Laws of the Issuer, dated as of December 17, 2008 |
| | |
1.3# | | Certificate and Articles of Incorporation of the Co-issuer (formerly 1425705 Alberta Ltd.), dated as of September 16, 2008, as amended by the Certificate of Amendment, dated as of October 15, 2008 |
| | |
1.4# | | By-Laws of the Co-issuer (formerly 1425705 Alberta Ltd.), dated as of September 16, 2008 |
| | |
1.5# | | Certificate and Articles of Incorporation of the Parent (formerly 1427258 Alberta ULC), dated as of September 23, 2008, as amended by the Certificate of Amendment and Registration of Restated Articles, dated as of December 12, 2008, as amended by the Certificate of Amendment, dated as of May 6, 2009 |
| | |
1.6# | | By-Laws of the Parent (formerly 1427258 Alberta ULC), dated as of September 23, 2008 |
| | |
1.7# | | Certificate of Incorporation of Gibson Energy (U.S.), Inc., dated as of June 5, 2006 |
| | |
1.8# | | By-Laws of Gibson Energy (U.S.), Inc. |
| | |
1.9# | | Certificate and Articles of Incorporation of Link Petroleum, Inc. (formerly Desticon Gas Liquids, Inc.), dated as of September 25, 1989, as amended by the Certificate of Administrative Dissolution, dated as of December 24, 1990, as amended by the Certificate of Reinstatement, dated as of June 25, 1991, as amended by the Certificate of Amendment, dated as of November 30, 1994 |
| | |
1.10* | | Amended and Restated By-Laws of Link Petroleum, Inc. (formerly Desticon Gas Liquids, Inc.), dated as of April 12, 2010 |
| | |
1.11# | | Amended and Restated Partnership Agreement of Moose Jaw Refinery Partnership, dated as of October 1, 2008, as amended by the Amendment to Declaration of Partnership, dated as of October 6, 2008, as amended by the Amendment to Declaration of Partnership, dated as of January 9, 2009 |
| | |
1.12# | | Contribution Agreement between Gibson Energy Ltd. and Moose Jaw Refinery Partnership, dated as of October 1, 2008 |
| | |
1.13# | | Certificate and Articles of Incorporation of Moose Jaw Refinery ULC, dated as of September 12, 2008 |
| | |
1.14# | | By-Laws of Moose Jaw Refinery ULC, dated as of September 12, 2008 |
| | |
1.15# | | Amended and Restated Partnership Agreement of Canwest Propane Partnership, dated as of October 1, 2008, as amended by the Amendment to Declaration of Partnership, dated as of October 6, 2008, as amended by the Amendment to Declaration of Partnership, dated as of January 9, 2009 |
| | |
1.16# | | Contribution Agreement between Gibson Energy Ltd. and Canwest Propane Partnership, dated as of October 1, 2008 |
| | |
1.17# | | Certificate and Articles of Incorporation of Canwest Propane ULC, dated as of September 12, 2008 |
| | |
1.18# | | By-Laws of Canwest Propane ULC, dated as of September 12, 2008 |
| | |
1.19# | | Amended and Restated Partnership Agreement of MP Energy Partnership, dated as of October 1, 2008, as amended by the Amendment to Declaration of Partnership, dated as of October 6, 2008, as amended by the Amendment to Declaration of Partnership, dated as of January 9, 2009 |
| | |
1.20# | | Contribution Agreement between Gibson Energy Ltd. and MP Energy Partnership, dated as of October 1, 2008 |
| | |
1.21# | | Certificate and Articles of Incorporation of MP Energy ULC, dated as of September 12, 2008 |
| | |
1.22# | | By-Laws of MP Energy ULC, dated as of September 12, 2008 |
| | |
1.23# | | Amended and Restated Partnership Agreement of Gibson Energy Partnership, dated as of October 1, 2008, as amended by the Amendment to Declaration of Partnership, dated as of October 6, 2008, as amended by the Amendment to Declaration of Partnership, dated as of January 9, 2009 |
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1.24# | | Contribution Agreement between Gibson Energy Ltd. and Gibson Energy Partnership, dated as of October 1, 2008 |
| | |
1.25# | | Certificate and Articles of Incorporation of GEP ULC, dated as of September 12, 2008 |
| | |
1.26# | | By-Laws of GEP ULC, dated as of September 12, 2008 |
| | |
1.27# | | Certificate and Articles of Incorporation of Link Petroleum Services Ltd. (formerly Desticon Gas Liquids Enterprises Ltd.), dated as of July 18, 1989, as amended by the Certificate of Change of Name, dated as of June 2, 1994 |
| | |
1.28# | | Certificate and Articles of Incorporation of Chief Hauling Contractors ULC (formerly 1110066 Alberta Ltd.), dated as of May 27, 2004, as amended by the Certificate of Amendment, dated as of August 19, 2004, as amended by the Certificate of Amendment and Registration of Restated Articles, dated as of December 15, 2008 |
| | |
1.29# | | By-Laws of Chief Hauling Contractors ULC (formerly 1110066 Alberta Ltd.), dated as of May 27, 2004 |
| | |
1.30# | | Memorandum and Articles of Association of Gibson GCC Inc. (formerly Gibson Capital Corporation), dated as of December 7, 2001, as amended by the Notice of Amendment of Memorandum and Articles of Incorporation, dated as of December 7, 2001, as amended by the Certificate of Continuance and Articles of Continuance, dated as of December 16, 2005 |
| | |
1.31# | | By-Laws of Bridge Creek Trucking Ltd., dated as of April 30, 2009 |
| | |
1.32# | | Certificate and Articles of Amalgamation of Johnstone Tank Trucking Ltd., dated as of January 27, 2010 |
| | |
1.33# | | By-Laws of Johnstone Tank Trucking Ltd., dated as of August 15, 1980 |
| | |
1.34* | | Certificate of Incorporation of Gibson (U.S.) Acquisitionco Corp., dated as of April 8, 2010 |
| | |
1.35* | | By-Laws of Gibson (U.S.) Acquisitionco Corp., dated as of April 16, 2010 |
| | |
2.1# | | Indenture among the Issuer, the Co-issuer, the subsidiary guarantors party thereto, and The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes Due 2014, dated as of May 27, 2009 |
| | |
2.2# | | Registration Rights Agreement among the Issuer, the Co-issuer, the subsidiary guarantors party thereto, and UBS Securities LLC, RBS Securities Inc. and RBC Capital Markets Corporation, as initial purchasers, relating to the 11.75% First Lien Senior Secured Notes Due 2014, dated as of May 27, 2009 |
| | |
2.3# | | Intercreditor Agreement among BNY Trust Company of Canada, as note agent and depositary, Royal Bank of Canada, as collateral agent, and Issuer, as borrower, dated as of May 27, 2009 |
| | |
2.4# | | Notation of Guarantee provided by Gibson Energy (U.S.) Inc. and Link Petroleum, Inc., dated as of May 27, 2009 |
| | |
2.5# | | Issuers and Parent Security Agreement among the Issuer, Co-issuer, and Parent, as obligors and BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.6# | | Subsidiary Guarantors Security Agreement among the subsidiary guarantors party thereto, as obligors and BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.7# | | Issuers Guarantee among the Issuer and Co-issuer as guarantors, the Bank of New York Mellon, as trustee, BNY Trust Company of Canada, as collateral agent, and the noteholders, as other secured creditors, dated as of May 27, 2009 |
| | |
2.8# | | Parent Guarantee among the Parent, as guarantor, the Bank of New York Mellon, as trustee, BNY Trust Company of Canada, as collateral agent, and the noteholders, as other secured creditors, dated as of May 27, 2009 |
| | |
2.9# | | Subsidiary Guarantors Guarantee among the subsidiary guarantors party thereto as Guarantors, the Bank of New York Mellon as trustee, BNY Trust Company of Canada, as collateral agent, and the noteholders as other secured creditors, dated as of May 27, 2009 |
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2.10# | | Issuer Demand Debenture among the Issuer as obligor and BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.11# | | Co-issuer, Parent, and subsidiary guarantors Demand Debenture among the Co-issuer, Parent, and subsidiary guarantors party thereto, as obligors and BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.12# | | Borrower Security Agreement among Gibson Acquisition ULC, as the grantor and Royal Bank of Canada, as the collateral agent and administrative agent, dated as of December 12, 2008 |
| | |
2.13# | | Guarantors Security Agreement among the Parent, Co-issuer, and subsidiary guarantors party thereto, as grantors and Royal Bank of Canada, as the collateral agent and administrative agent, dated as of December 12, 2008 |
| | |
2.14# | | Indenture among the Issuer, the Co-issuer, the subsidiary guarantors party thereto, and The Bank of New York Mellon, as trustee, relating to the 10.00% Senior Notes Due 2018, dated as of January 19, 2010 |
| | |
2.15# | | Registration Rights Agreement among the Issuer, the Co-issuer, the subsidiary guarantors party thereto, and UBS Securities LLC, Morgan Stanley & Co. Incorporated and RBC Capital Markets Corporation, as initial purchasers, relating to the 10.00% Senior Notes Due 2018, dated as of January19, 2010 |
| | |
2.16# | | Notation of Guarantee provided by Gibson Energy (U.S.) Inc. and Link Petroleum, Inc., dated as of January 19, 2010 |
| | |
2.17# | | Issuers Guarantee among the Issuer and Co-issuer, as guarantors, The Bank of New York Mellon, as trustee, and the noteholders, as other creditors, dated as of January 19, 2010 |
| | |
2.18# | | Parent Guarantee among the Parent, as guarantor, The Bank of New York Mellon, as trustee, and the noteholders, as other creditors, dated as of January 19, 2010 |
| | |
2.19# | | Subsidiary Guarantors Guarantee among the subsidiary guarantors party thereto, as guarantors, The Bank of New York Mellon, as trustee, and the noteholders, as other creditors, dated as of January 19, 2010 |
| | |
2.20# | | First Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes Due 2014, dated as of January 11, 2010 |
| | |
2.21# | | Form of Note relating to the 11.75% First Lien Senior Secured Notes Due 2014 |
| | |
2.22# | | Form of Note relating to the 10.00% Senior Notes Due 2018 |
| | |
2.23# | | Intercreditor Agreement among Gibson Acquisition ULC and the Issuer, as borrower, and Royal Bank of Canada, as first lien bridge agent and depository, second lien bridge agent, and collateral agent, dated as of December 12, 2008 |
| | |
2.24# | | Joinder Agreement of Johnstone Tank Trucking Ltd., dated as of February 9, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.25# | | Joinder Agreement of Johnstone Tank Trucking Ltd., dated as of February 9, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.26# | | Joinder Agreement of Johnstone Tank Trucking Ltd., dated as of February 9, 2010, to the Guarantee—Subsidiary Guarantors relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of The Bank of New York Mellon, as trustee, dated as of May 27, 2009 |
| | |
2.27# | | Joinder Agreement of Johnstone Tank Trucking Ltd., dated as of February 9, 2010, to the Guarantee—Subsidiary Guarantors relating to the 10.00% Senior Notes due 2018 among the subsidiary guarantors party thereto, in favor of The Bank of New York Mellon, as trustee, dated as of January 19, 2010 |
| | |
2.28* | | Second Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes due 2014, dated as of February 12, 2010 |
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2.29* | | First Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, and The Bank of New York Mellon, as trustee, relating to the 10.00% Senior Notes due 2018, dated as of April 26, 2010 |
| | |
2.30* | | Third Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes due 2014, dated as of April 26, 2010 |
| | |
2.31* | | Joinder Agreement of Gibson (U.S.) Acquisitionco Corp., dated as of April 26, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.32* | | Joinder Agreement of Gibson (U.S.) Acquisitionco Corp., dated as of April 26, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.33† | | Fourth Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes due 2014, dated as of June 14, 2010 |
| | |
2.34† | | Fifth Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes due 2014, dated as of September 20, 2010 |
| | |
2.35† | | Joinder Agreement of Battle River Terminal ULC, as of September 20, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.36† | | Second Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, and The Bank of New York Mellon, as trustee, relating to the 10.00% Senior Notes due 2018, dated as of June 14, 2010 |
| | |
2.37† | | Joinder Agreement of Taylor Gas Liquids, LLC., dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.38† | | Joinder Agreement of TPG Leasing, LLC., dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.39† | | Sixth Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes due 2014, dated as of December 23, 2010 |
| | |
2.40† | | Seventh Supplemental Indenture among the Issuer, Co-issuer, the subsidiary guarantors party thereto, The Bank of New York Mellon, as trustee, and BNY Trust Company of Canada, as collateral agent, relating to the 11.75% First Lien Senior Secured Notes due 2014, dated as of February 11, 2011 |
| | |
2.41† | | Joinder Agreement of Taylor Companies, LLC, dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.42† | | Joinder Agreement of TPG Leasing, LLC, dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.43† | | Joinder Agreement of TPG Transport, LLC, dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.44† | | Joinder Agreement of Taylor Transfer Services, LLC, dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
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2.45† | | Joinder Agreement of Gibson (U.S.) Holdco Corp., dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.46† | | Joinder Agreement of Gibson (U.S.) Finco Corp., dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.47† | | Joinder Agreement of Gibson Finance Ltd., dated as of June 14, 2010, to the Demand Debenture relating to the 11.75% First Lien Senior Secured Notes due 2014 among the Co-issuer, Parent, and subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.48† | | Joinder Agreement of Taylor Transfer Services, LLC, dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.49† | | Joinder Agreement of Taylor Transport, LLC, dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.50† | | Joinder Agreement of Taylor Companies, LLC, dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.51† | | Joinder Agreement of Taylor Gas Liquids, LLC, dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.52† | | Joinder Agreement of Gibson (U.S.) Holdco Corp., dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.53† | | Joinder Agreement of Gibson (U.S.) Finco Corp., dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
2.54† | | Joinder Agreement of Gibson Finance Ltd., dated as of June 14, 2010, to the Security Agreement relating to the 11.75% First Lien Senior Secured Notes due 2014 among the subsidiary guarantors party thereto, in favor of BNY Trust Company of Canada, as collateral agent, dated as of May 27, 2009 |
| | |
4.1# | | Credit Agreement among Gibson Acquisition ULC as borrower, Parent, Co-issuer, and subsidiary guarantors party thereto, as guarantors, the financial institutions named therein, as lenders, Royal Bank of Canada, as administrative agent and collateral agent, Royal Bank of Canada, as syndication agent, UBS Securities LLC, as documentation agent, and RBC Capital Markets and UBS Securities LLC, as lead arrangers, dated as of December 12, 2008 |
| | |
4.2# | | First Amendment to Credit Agreement among the Issuer, as borrower, the Co-issuer and subsidiary guarantors party thereto, as guarantors, Royal Bank of Canada, as administrative agent, and Royal Bank of Canada and UBS Loan Finance LLC, as lenders, dated as of May 26, 2009 |
| | |
4.3# | | Second Amendment to Credit Agreement among the Issuer, as borrower, the Co-issuer and subsidiary guarantors party thereto, as guarantors, Royal Bank of Canada, as administrative agent, and Royal Bank of Canada, UBS Loan Finance LLC, Bank of Montreal, and the other financial institutions named therein, as lenders, dated as of October 2, 2009 |
| | |
4.4# | | Third Amendment to Credit Agreement among the Issuer, as borrower, the Co-issuer and subsidiary guarantors party thereto, as guarantors, Royal Bank of Canada, as administrative agent, and Royal Bank of Canada, UBS Loan Finance LLC, Bank of Montreal, and Morgan Stanley Bank, N.A., as lenders, dated as of January 13, 2010 |
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4.5** | | Amended and Restated Credit Agreement, dated as of September 17, 2010, among Gibson Energy ULC, as Canadian Borrower, the U.S. Borrowers party thereto, the Guarantors party thereto, the Lenders party thereto and Royal Bank of Canada as administrative agent for the lenders. |
| | |
4.6# | | Appendix A to Stock Option Agreement |
| | |
4.7# | | Supplemental Non-registered Savings Plan, dated as of April 1, 2009 |
| | |
4.8# | | Equity Incentive Plan |
| | |
7.1† | | Computation of Earnings to Fixed Charges |
| | |
8.1† | | List of Subsidiaries |
| | |
12.1† | | Certification of A. Stewart Hanlon, Chief Executive Officer of Gibson Energy ULC, pursuant to 15 U.S.C. Section 78(m)(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| | |
12.2† | | Certification of Richard G. Taylor, Chief Financial Officer of Gibson Energy ULC, pursuant to 15 U.S.C. Section 78(m)(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 |
| | |
13.1† | | Certification of A. Stewart Hanlon, Chief Executive Officer of Gibson Energy ULC, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
| | |
13.2† | | Certification of Richard G. Taylor, Chief Financial Officer of Gibson Energy ULC, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
# | | Incorporated by reference to the Registration statement filed on Form F-4 of Gibson Energy ULC filed on February 12, 2010. |
| | |
* | | Incorporated by reference to the Registration statement filed on Form F-4/A of Gibson Energy ULC filed on April 26, 2010. |
| | |
** | | Incorporated by reference to the Current report filed on Form 6-K of Gibson Energy ULC filed on September 23, 2010. |
| | |
† | | filed herewith |
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SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.
| GIBSON ENERGY ULC |
| |
| |
| /s/ A. Stewart Hanlon |
| Name: A. Stewart Hanlon |
| Title: President and Chief Executive Officer |
| |
Date: April 29, 2011 | |
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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page |
Reports of Independent Registered Public Accounting Firm | F-2 |
| |
Consolidated Balance Sheets as of December 31, 2010 and 2009 | F-4 |
| |
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) and Retained Earnings (Deficit) for the years ended December 31, 2010 and 2009, for the period from January 1, 2008 to December 12, 2008 and for the period from December 13, 2008 to December 31, 2008 | F-6 |
| |
Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009, for the period from January 1, 2008 to December 12, 2008 and for the period from December 13, 2008 to December 31, 2008 | F-8 |
| |
Notes to Consolidated Financial Statements | F-9 |
F-1
Table of Contents
| PricewaterhouseCoopers LLP |
| Chartered Accountants |
| 111 5th Avenue SW, Suite 3100 |
| Calgary, Alberta |
| Canada T2P 5L3 |
| Telephone +1 (403) 509 7500 |
| Facsimile +1 (403) 781 1825 |
| www.pwc.com/ca |
April 15, 2009
Report of Independent Registered Public Accounting Firm
To the Shareholder of
Gibson Energy Holding ULC
We have audited the consolidated statements of income and comprehensive income and retained earnings and cash flows for the period from January 1, 2008 to December 12, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
As discussed in Note 2 to the consolidated financial statements, effective December 12, 2008, Gibson Energy Holdings Inc. was acquired by Riverstone Holdings LLC in a business combination accounted for under the purchase method. As a result of the acquisition, the consolidated financial statements for the Successor Company are presented on a different cost basis than that of the Predecessor Company which has a material effect on the comparability of the Company’s consolidated financial statements. As discussed in Note 1 to the consolidated financial statements, during 2009 the Company adopted CICA Handbook Section 3064 “Goodwill and Intangible Assets”, and changed the manner in which it accounts for pre-operating expenditures.
In our opinion, these consolidated financial statements present fairly, in all material respects, the results of its operations and its cash flows for the period from January 1, 2008 to December 12, 2008 in accordance with Canadian generally accepted accounting principles.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership, which is a member firm of PricewaterhouseCoopers International Limited, each member firm of which is a separate legal entity.
F-2
Table of Contents
| PricewaterhouseCoopers LLP |
| Chartered Accountants |
| 111 5th Avenue SW, Suite 3100 |
| Calgary, Alberta |
| Canada T2P 5L3 |
| Telephone +1 (403) 509 7500 |
| Facsimile +1 (403) 781 1825 |
| www.pwc.com/ca |
March 15, 2011
Report of Independent Registered Public Accounting Firm
To the Shareholder of
Gibson Energy Holding ULC
We have audited the consolidated balance sheets of Gibson Energy Holding ULC as at December 31, 2010 and December 31, 2009 and the consolidated statements of income (loss) and retained earnings (deficit), comprehensive income (loss) and retained earnings and cash flows for the years ended December 31, 2010 and December 31, 2009 and for the period from December 13, 2008 to December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
As discussed in Note 2 to the consolidated financial statements, effective December 12, 2008, Gibson Energy Holdings Inc. was acquired by Riverstone Holdings LLC in a business combination accounted for under the purchase method. As a result of the acquisition, the consolidated financial statements for the Successor Company are presented on a different cost basis than that of the Predecessor Company which has a material effect on the comparability of the Company’s consolidated financial statements. As discussed in Note 1 to the consolidated financial statements, during 2009 the Company adopted CICA Handbook Section 3064 “Goodwill and Intangible Assets”, and changed the manner in which it accounts for pre-operating expenditures.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2010 and December 31, 2009 and the results of its operations and its cash flows for the years ended December 31, 2010 and December 31, 2009 and for the period from December 13, 2008 to December 31, 2008 in accordance with Canadian generally accepted accounting principles.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
“PricewaterhouseCoopers” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership, which is a member firm of PricewaterhouseCoopers International Limited, each member firm of which is a separate legal entity.
F-3
Table of Contents
Gibson Energy Holding ULC
Consolidated Balance Sheets
(tabular amounts in thousands of Canadian dollars)
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Assets | | | | | |
| | | | | |
Current assets | | | | | |
Cash and cash equivalents (note 13) | | $ | 7,225 | | $ | 26,263 | |
Accounts receivable (note 3) | | 354,682 | | 315,865 | |
Income taxes receivable | | 57,130 | | 15,541 | |
Inventories (note 4) | | 197,483 | | 113,688 | |
Current portion of future income taxes (note 17) | | — | | 1,509 | |
Prepaid expenses | | 8,749 | | 5,187 | |
Net investment in capital leases | | 236 | | — | |
Assets held for sale | | 32,985 | | — | |
Total current assets | | 658,490 | | 478,053 | |
| | | | | |
Future income taxes (note 17) | | 13,422 | | 5,225 | |
| | | | | |
Long-term prepaid expenses and other assets (note 5) | | 24,276 | | 30,941 | |
| | | | | |
Net investment in capital leases (note 6) | | 20,265 | | — | |
| | | | | |
Property, plant and equipment (note 7) | | 652,885 | | 598,826 | |
| | | | | |
Intangible assets (note 8) | | 154,610 | | 126,955 | |
| | | | | |
Goodwill (note 10) | | 498,817 | | 433,894 | |
Total assets | | $ | 2,022,765 | | $ | 1,673,894 | |
See accompanying notes
F-4
Table of Contents
Gibson Energy Holding ULC
Consolidated Balance Sheets
(tabular amounts in thousands of Canadian dollars)
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Liabilities | | | | | |
| | | | | |
Current liabilities | | �� | | | |
Credit facility (note 13) | | $ | 43,500 | | $ | 25,000 | |
Accounts payable and accrued charges (note 11) | | 393,686 | | 254,869 | |
Deferred revenue | | 54,701 | | 13,405 | |
Income taxes payable | | 1,217 | | 8,443 | |
Current portion of future income taxes (note 17) | | 177 | | 839 | |
Liabilities related to assets held for sale | | 2,960 | | — | |
Total current liabilities | | 496,241 | | 302,556 | |
| | | | | |
Asset retirement obligation (note 12) | | 9,614 | | 8,287 | |
| | | | | |
Long-term debt (note 14) | | 718,154 | | 553,942 | |
| | | | | |
Other long-term liabilities (note 15) | | 15,655 | | 16,092 | |
| | | | | |
Future income taxes (note 17) | | 196,440 | | 204,373 | |
| | | | | |
Commitments and contingencies (note 22) | | | | | |
| | | | | |
Shareholder’s Equity | | | | | |
| | | | | |
Share capital (note 23) | | | | | |
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 | | 127,068 | | 113,034 | |
Total share capital | | 664,724 | | 650,690 | |
| | | | | |
Contributed surplus (note 19) | | 13,586 | | 8,957 | |
| | | | | |
Accumulated other comprehensive loss | | (6,767 | ) | — | |
| | | | | |
Deficit | | (84,882 | ) | (71,003 | ) |
Total shareholder’s equity | | 586,661 | | 588,644 | |
Total liabilities and shareholder’s equity | | $ | 2,022,765 | | $ | 1,673,894 | |
See accompanying notes
F-5
Table of Contents
Gibson Energy Holding ULC
Consolidated Statements of Income (Loss) and Retained Earnings (Deficit)
(tabular amounts in thousands of Canadian dollars)
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Period from
December 13,
2008 to
December 31,
2008 | | Period from
January 1,
2008 to
December 12,
2008 | |
Revenue | | | | | | | | | |
Products | | $ | 3,253,632 | | $ | 3,162,806 | | $ | 117,501 | | $ | 4,307,931 | |
Services | | 424,356 | | 291,331 | | 17,970 | | 340,734 | |
Total revenues | | 3,677,988 | | 3,454,137 | | 135,471 | | 4,648,665 | |
Cost of sales, excluding depreciation and amortization | | | | | | | | | |
Cost of products | | 3,247,033 | | 3,120,713 | | 113,295 | | 4,270,209 | |
Cost of services | | 259,526 | | 171,708 | | 11,677 | | 220,930 | |
Total cost of sales, excluding depreciation and amortization | | 3,506,559 | | 3,292,421 | | 124,972 | | 4,491,139 | |
| | 171,429 | | 161,716 | | 10,499 | | 157,526 | |
Operating expenses | | | | | | | | | |
Depreciation of property, plant and equipment | | 64,968 | | 56,564 | | 3,558 | | 28,397 | |
General and administrative | | 24,935 | | 24,731 | | 615 | | 31,365 | |
Amortization of intangible assets | | 29,177 | | 25,747 | | 1,323 | | 3,109 | |
Stock based compensation (note 19) | | 4,629 | | 8,957 | | — | | — | |
Loss (gain) on sale of assets | | (37 | ) | (90 | ) | 18 | | (108 | ) |
Impairment of goodwill and intangible assets (note 8 and 10) | | — | | 114,115 | | — | | — | |
Other non-operating expenses (income) | | | | | | | | | |
Accretion expense | | 787 | | 785 | | 22 | | 404 | |
Foreign exchange gain | | (39,880 | ) | (92,681 | ) | (4,487 | ) | (483 | ) |
Debt extinguishment costs (note 14) | | — | | 18,517 | | — | | — | |
Loss from equity investments | | 914 | | 54 | | 21 | | 336 | |
Interest expense (income) | | | | | | | | | |
Long-term debt | | 96,345 | | 80,169 | | 3,430 | | — | |
Due to affiliates | | — | | — | | — | | 8,280 | |
Income | | (324 | ) | (253 | ) | (12 | ) | (346 | ) |
Other | | 3,106 | | 699 | | 1 | | 55 | |
| | 184,620 | | 237,314 | | 4,489 | | 71,009 | |
Income (loss) before income taxes | | (13,191 | ) | (75,598 | ) | 6,010 | | 86,517 | |
| | | | | | | | | |
Income tax provision (recovery) (note 17) | | | | | | | | | |
Current | | 2,779 | | (226 | ) | 280 | | 33,981 | |
Future | | (16,125 | ) | (12,423 | ) | 750 | | (8,782 | ) |
| | (13,346 | ) | (12,649 | ) | 1,030 | | 25,199 | |
| | | | | | | | | |
Net income (loss) | | 155 | | (62,949 | ) | 4,980 | | 61,318 | |
| | | | | | | | | |
Retained earnings — beginning of period | | (71,003 | ) | 4,355 | | — | | 257,765 | |
Dividends on preferred shares (note 23) | | (14,034 | ) | (12,409 | ) | (625 | ) | — | |
Retained earnings (deficit) - end of period | | $ | (84,882 | ) | $ | (71,003 | ) | $ | 4,355 | | $ | 319,083 | |
See accompanying notes
F-6
Table of Contents
Gibson Energy Holding ULC
Consolidated Statement of Comprehensive Income (Loss)
(tabular amounts in thousands of Canadian dollars)
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Period from
December 13,
2008 to
December 31,
2008 | | Period from
January 1,
2008 to
December 12,
2008 | |
| | | | | | | | | |
Net income (loss) | | $ | 155 | | $ | (62,949 | ) | $ | 4,980 | | $ | 61,318 | |
| | | | | | | | | |
Other comprehensive loss , net of tax | | | | | | | | | |
Foreign currency translation adjustment | | (6,767 | ) | — | | — | | — | |
Comprehensive income (loss) | | $ | (6,612 | ) | $ | (62,949 | ) | $ | 4,980 | | $ | 61,318 | |
See accompanying notes
F-7
Table of Contents
Gibson Energy Holding ULC
Consolidated Statement of Cash Flows
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Period from
December 13,
2008 to
December 31,
2008 | | Period from
January 1,
2008 to
December 12,
2008 | |
Cash provided by (used in) | | | | | | | | | |
Operating activities | | | | | | | | | |
Net income (loss) | | $ | 155 | | $ | (62,949 | ) | $ | 4,980 | | $ | 61,318 | |
Items not affecting cash | | | | | | | | | |
Depreciation and amortization | | 94,145 | | 82,311 | | 4,881 | | 31,506 | |
Stock based compensation | | 4,629 | | 8,957 | | — | | — | |
Future income taxes | | (16,125 | ) | (12,423 | ) | 750 | | (8,782 | ) |
Accretion expense | | 787 | | 785 | | 22 | | 404 | |
Accretion related to long-term debt | | 6,628 | | 11,890 | | 395 | | — | |
Loss (gain) on disposal of assets | | (37 | ) | (90 | ) | 18 | | (108 | ) |
Unrealized loss (gain) on financial instruments | | (1,373 | ) | 9,692 | | 1,457 | | (8,347 | ) |
Inventory write-down | | — | | — | | — | | 1,206 | |
Foreign exchange gain on long-term debt | | (36,760 | ) | (97,991 | ) | (5,069 | ) | — | |
Debt extinguishment costs | | — | | 18,517 | | — | | — | |
Impairment of goodwill and intangible assets | | — | | 114,115 | | — | | — | |
Other | | 369 | | (699 | ) | (63 | ) | 279 | |
Net change in non-cash working capital (note 21) | | (758 | ) | (70,045 | ) | 29,466 | | (3,428 | ) |
Net cash provided by operating activities | | 51,660 | | 2,070 | | 36,837 | | 74,048 | |
Investing activities | | | | | | | | | |
Purchase of property, plant and equipment | | (61,682 | ) | (36,967 | ) | (2,982 | ) | (43,672 | ) |
Equity investments | | (3,050 | ) | (6,643 | ) | — | | (3,750 | ) |
Proceeds on disposal of assets | | 2,750 | | 998 | | 695 | | 9,141 | |
Increase in long-term prepaid and other assets | | 713 | | (5,857 | ) | (1,697 | ) | (13,116 | ) |
Acquisitions, net of cash acquired (note 2 and note 9) | | (232,746 | ) | (15,165 | ) | (982,365 | ) | (14,430 | ) |
Net change in non-cash working capital | | 12,280 | | (31,569 | ) | 34,759 | | (8,709 | ) |
Net cash used in investing activities | | (281,735 | ) | (95,203 | ) | (951,590 | ) | (74,536 | ) |
Financing activities | | | | | | | | | |
Proceeds from long-term debt, net of debt discount (note 14) | | 200,888 | | 605,723 | | 672,476 | | — | |
Payment of debt issue costs | | (6,544 | ) | (15,904 | ) | (27,720 | ) | — | |
Repayments of bridge loans | | — | | (606,040 | ) | — | | — | |
Proceeds from credit facility | | 298,314 | | 25,000 | | — | | — | |
Repayment of credit facility | | (279,814 | ) | — | | — | | — | |
Proceeds from issuance of common shares (note 2) | | — | | — | | 380,656 | | — | |
Loans from affiliate | | — | | — | | — | | 125,000 | |
Advance received from Riverstone | | — | | — | | — | | 157,000 | |
Repayment of loans from affiliate | | — | | — | | — | | (289,500 | ) |
Repayment of capital lease obligations | | — | | — | | — | | (48 | ) |
Net change in non-cash working capital | | — | | (2,335 | ) | 2,293 | | — | |
Net cash provided by (used in) financing activities | | 212,844 | | 6,444 | | 1,027,705 | | (7,548 | ) |
Effect of exchange rate on cash and cash equivalents | | (1,807 | ) | — | | — | | — | |
Net increase (decrease) in cash and cash equivalents | | (19,038 | ) | (86,689 | ) | 112,952 | | (8,036 | ) |
Cash and cash equivalents — beginning of period | | 26,263 | | 112,952 | | — | | 25,061 | |
Cash and cash equivalents — end of period | | $ | 7,225 | | $ | 26,263 | | $ | 112,952 | | $ | 17,025 | |
See accompanying notes
F-8
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
1 Accounting policies
Basis of preparation
Gibson Energy Holding ULC (“Gibson”, or the “Successor”) was incorporated on July 11, 2008 by investment funds affiliated with Riverstone Holdings LLC (“Riverstone”), in order to acquire the outstanding common stock of Gibson Energy Holdings Inc. (the “Predecessor”) from Hunting PLC (“Hunting”). Effective on the close of business on December 12, 2008, Gibson acquired the Predecessor for $1,256,390,000 (the “Acquisition”), as more fully described in Note 2.
The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). As a result of the Acquisition, the consolidated financial statements subsequent to December 12, 2008 have been prepared using a new basis of measurement for the difference between the fair value and book value of the Predecessor assets acquired and liabilities assumed in the acquisition by the Successor as more fully described in Note 2. Because of the Acquisition, a different basis of accounting has been used to prepare the Successor and Predecessor (collectively the “Company”) consolidated financial statements. As a result, the consolidated statement of income and comprehensive income and retained earnings for the 19 day period subsequent to the acquisition reflects depreciation and amortization expense based on the new carrying values of the related assets and interest expense that resulted from the debt to finance the acquisition. The consolidated statement of income and comprehensive income and retained earnings for the period from January 1, 2008 to December 12, 2008 do not include the effects of the Acquisition. Therefore, the consolidated financial statements of Predecessor are not comparable with the consolidated financial statements of Successor. To indicate the application of a different basis of accounting for the period subsequent to the acquisition, the consolidated financial statements and certain notes to the consolidated financial statements present separately the periods prior to the Acquisition, namely the period from January 1, 2008 to December 12, 2008, and the periods after the Acquisition namely, the year ended December 31, 2010 (“2010”), the year ended December 31, 2009 (“2009”) and the period from December 13, 2008 to December 31, 2008.
Amounts are stated in Canadian dollars unless otherwise noted. References to “$” and “dollars” are to Canadian dollars and references to “U.S.$” and “U.S. Dollars” are to United States dollars. Certain reclassifications of prior year amounts have been made to conform to the current year presentation.
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. This business is typically referred to as the midstream energy business.
F-9
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Summary of significant differences between Canadian GAAP and U.S. GAAP
Accounting principles generally accepted under Canadian GAAP differ 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 25.
Use of estimates
Because the determination of many assets and liabilities is dependent upon future events, the preparation of these financial statements necessarily involves the use of estimates and approximations. Estimates are used in the assessment of the collectability of accounts receivable, the recoverability of the carrying value of goodwill, intangible assets and property, plant and equipment, future income taxes, asset retirement obligations, remediation liability, valuation of stock options, valuation of pension assets, liabilities and related expenses, the determination of certain future obligations and the purchase price allocation described in Note 2. In addition, estimates of the useful life of property, plant and equipment and intangible assets are required in order to calculate depreciation and amortization. The consolidated financial statements have, in management’s opinion, been properly prepared within reasonable limits of materiality and within the framework of the accounting policies summarized below. Actual results may differ from estimated amounts as future confirming events occur, and such differences may be material to the consolidated financial statements.
Revenue recognition
Product revenues associated with the sale of crude oil, diluent, natural gas liquids, asphalt, natural gas, wellsite fluids and distillate owned by the Company are recognized when persuasive evidence of an arrangement exists, title passes from the Company to its customers, which is when the risk of ownership passes to the customer and physical delivery occurs, the price is fixed and collection is reasonably assured. Sales terms are generally FOB shipping point, in which case the sales are recorded at the time of shipment, because this is when title and risk of loss are transferred. All payments received before delivery are recorded as deferred revenue and are recognized as revenue when delivery occurs, assuming all other criteria are met. Freight costs billed to customers are recorded as a component of revenue. Revenues from buy/sell transactions whereby the Company acts as an agent are recorded on a net basis.
Revenue associated with the provision of transportation and terminalling services are recognized when the services are provided, the price is fixed and collection is reasonably assured. Revenue from pipeline tariffs and fees are based on volumes and rates as the pipeline is being used. Revenue from non-refundable propane tank fees are recorded in deferred revenue and is recognized in revenue on a straight line basis over the rental period, typically one year.
Unrealized gains and losses from the Company’s risk management activities are recorded as revenue or cost of product based on the underlying financial instrument and the related mark to market calculation at the end of the year.
Excise taxes are reported gross within revenue.
F-10
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Principles of consolidation
The consolidated financial statements include the accounts of the Company and all of its wholly owned subsidiaries.
Inventories
Crude oil, asphalt, diluent, natural gas liquids, natural gas, wellsite fluids, distillate and spare parts are carried at the lower of average cost and net realizable value, with cost determined using a weighted average cost method.
Net investment in capital leases
Contractual arrangements that transfer substantially all the risks and benefits of ownership of property to the lessee and, at the inception of the lease, the fair value of the leased property is equal to the Company’s carrying amount of the property are recorded as a net investment in a capital lease. The minimum lease payments under such arrangements are recorded at the inception of the arrangement and the finance income is recognized in a manner that produces a consistent rate of return on the investment in the capital lease and is included in revenue.
Derivative financial instruments
Derivative financial instruments are used by the Company to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and certain operating costs.
The Company periodically enters into crude oil futures, swaps and option contracts to manage the price risk associated with sales, purchases and inventories of crude oil and petroleum products. The Company also periodically purchases foreign exchange forward contracts and options to manage foreign exchange exposures on sales to customers in the United States and the related accounts receivable and also on the U.S. dollar interest payments on long-term debt.
Derivative instruments, used periodically by the Company to manage exposure to market risks relating to commodity prices and foreign currency exchange rates, are not designated as hedges. They are recorded using the mark-to-market method of accounting whereby derivative instruments are recorded at fair value on the balance sheet as either an asset or liability with changes in fair value recorded to net earnings. The estimated fair value of all derivative instruments is based on quoted market prices, or, in their absence, third party market indications and forecasts. Realized gains or losses from financial derivatives related to commodity prices are recognized in revenues or cost of sales as the related sales occurred or the commodity has been delivered. Foreign exchange translation gains and losses on these instruments are recognized as an adjustment of revenues when the sale is recorded.
Equity method of accounting
When the Company has the ability to exercise significant influence, the Company’s pro-rata share of post-acquisition net income or loss is reflected as a one line item on the statement of income and will increase or decrease, as applicable, with the carrying value of the investments on the balance sheet. The Company does not consolidate any part of the assets or liabilities of its equity investments.
F-11
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Property, plant and equipment
The Company carries property, plant and equipment at cost, net of government assistance, and provides depreciation and amortization on a straight-line basis at rates varying from 3% to 33% which are designed to amortize the cost of the assets over their estimated useful lives.
Depreciation rates are as follows:
Buildings | | 10 — 20 years | |
Equipment | | 3 — 20 years | |
Rolling stock | | 10 — 23 years | |
Pipelines | | 8 — 20 years | |
Tanks | | 20 — 33 years | |
Plants | | 3 — 25 years | |
The Company evaluates the carrying value of its property, plant and equipment whenever events or conditions occur that indicate that the carrying value on the balance sheet may not be recoverable from future cash flows. If the carrying value exceeds the sum of undiscounted future cash flows, the property’s carrying value is impaired. The property is then assigned a new cost basis, based on fair value equal to its estimated total future cash flows, discounted for the time value of money, and the Company expenses the excess carrying value as an impairment charge in the statement of income. The future cash flow estimates require assumptions about future revenues, operating costs and other factors. Actual results can differ from these estimates.
Intangible assets
The Company carries intangible assets at cost and provides amortization on a straight-line basis, which is designed to amortize the cost of the assets over their estimated useful lives. Amortization rates are as follows:
Technology | | 3 — 5 years | |
Customer relationships | | 4 — 12 years | |
Brands | | 10 years | |
Non-compete agreements | | 2 — 10 years | |
Long-term customer contracts | | 6 — 10 years | |
Intangible assets are reviewed for impairment whenever events or conditions indicate that their net carrying amount may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset’s fair value is recognized during the period, with a charge to the statement of income.
F-12
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Goodwill
Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is evaluated for impairment on an annual basis, or more frequently if events and circumstances indicate that the carrying amount may not be recoverable. Goodwill and all other assets and liabilities have been allocated to business levels referred to as reporting units. The fair value of each reporting unit is determined using a discounted cash flow model and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting unit’s individual assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is recorded as an impairment charge in the statement of income.
Asset retirement obligation
The fair value of obligations associated with site restoration on the retirement of assets with determinable useful lives, such as terminal sites, pipelines, asphalt refinery and fractionation plant, are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially measured at fair value based on discounted future costs. A corresponding amount equal to that of the initial obligation is added to the capitalized costs of the related asset. Over time the discounted asset retirement obligation amount will be accreted for the change in its present value, and the initial capitalized costs will be depreciated over the useful lives of the facilities. Actual expenditures incurred are charged against the accumulated obligation.
Environmental liabilities
The Company records environmental liabilities when environmental assessments or remedial efforts are probable and costs can be reasonably estimated. Generally, the recording of these accruals coincides with the completion of a feasibility study or a commitment to a formal plan of action.
Debt issuance costs
Debt issuance costs that are directly attributable to the issuance of the debt, such as debt discount and fees paid to lending institutions and other third parties are included in the carrying amount of the related financial liability and amortized under the effective interest method over the terms of the underlying debt instrument.
Income taxes
The Company follows the liability method of accounting for income taxes. Future income tax assets and liabilities are determined based on differences between the financial reporting and income tax basis of assets and liabilities. These differences are then measured using substantively enacted income tax rates and laws that will be in effect when these differences are expected to reverse. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period that the change occurs.
The Company is entitled to investment tax credits (“ITCs”) based on certain research and experimental development costs incurred. Investment tax credits and other cost recoveries related to property and equipment are credited against the book value of property and equipment and the credit is released to income
F-13
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
on a straight-line basis as a reduction of amortization expense over the above mentioned estimated useful lives of the relevant assets.
Employee future benefits
a) Defined benefit pension plans and post retirement benefits
The estimated future cost of providing defined benefit pension and other post-retirement benefits (“OPRB”) is actuarially determined using management’s best estimates of demographic and financial assumptions, and such cost is accrued proportionately from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based on a year-end market rate of interest for high-quality debt instruments with cash flows that match the timing and amount of expected benefit payments.
b) Defined contribution pension plans
The Company’s defined contribution plans are funded as specified in the plans and the pension expense is recorded as payments are incurred.
Stock based compensation
The Company estimates the grant-date fair value of stock options using a Black-Scholes valuation model. The options have a graded vesting schedule and each vesting portion is amortized separately on a straight-line basis over the vesting period with a corresponding credit to contributed surplus. Upon exercise, the associated amount is reclassified from contributed surplus to share capital. Consideration received from employees upon exercise of options is credited to share capital.
Cash and cash equivalents
Cash and cash equivalents include cash and short-term, highly liquid investments with original maturities of 90 days or less.
Foreign exchange translation
The financial statements for each of the Company’s subsidiaries are prepared using their functional currency. The functional currency is the currency of the primary economic environment in which an entity operates. The presentation and functional currency of the Company is Canadian dollars. Assets and liabilities of foreign operations are translated into Canadian dollars at the market rates prevailing at the balance sheet date. Operating results are translated at the average rates for the period. Exchange differences arising on the consolidation of the net assets of foreign operations are recorded in other comprehensive income.
Foreign currency transactions are translated using exchange rates prevailing at the transaction date. Generally, foreign exchange gains and losses resulting from the settlement of foreign currency transactions and from the translation at period end exchange rates of monetary assets and liabilities denominated in currencies other than an entity’s functional currency are recognized in the statement of income.
F-14
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
2 Acquisition
On August 5, 2008, Hunting and Gibson Acquisition ULC, a wholly owned subsidiary of Gibson Energy Holding ULC, entered into a sale and purchase agreement pursuant to which Gibson Acquisition ULC acquired all of the issued and outstanding Class A and Class B Common Shares of Gibson Energy Holdings Inc. Following the Acquisition, a number of Gibson entities, including Gibson Energy Holdings Inc., converted to unlimited liability companies. Gibson Energy Holdings ULC then amalgamated with Gibson Energy Ltd. (following its conversion to an unlimited liability company), a subsidiary of Gibson Energy Holding ULC, and the surviving entity of that amalgamation has subsequently been amalgamated with Gibson Acquisition ULC to form Gibson Energy ULC, a wholly owned subsidiary.
The total consideration for the Acquisition was $1,256,390,000, which includes cash payments at closing of $999,390,000, $157,000,000 of cash advanced to the Company prior to the Acquisition and $100,000,000 of deferred consideration. As part of the consideration, the Company’s former parent, Hunting agreed to a two-year deferral of $100,000,000 of the consideration, and took back as collateral, a warrant that entitled them to 100,000 preferred shares in the Company’s parent. The preferred shares carry an annual dividend that is cumulative and compounding. If the $100,000,000 of deferred consideration is not settled within two years, the warrant automatically converts to preferred shares of the Company’s parent company that are automatically exchanged into a separate class of common shares of the parent. As consideration for the warrant, the Company issued 100,000 common shares to its parent (note 23).
The Acquisition was financed by borrowings under credit agreements and from equity contributions by Riverstone. Riverstone capitalized the Company with cash of $537,656,000 in exchange for 537,656 Class A common shares. As part of the capitalization, Riverstone contributed to the Company certain foreign exchange contracts with a negative value of $169,049,000. Subsequent to contributing the contracts, Riverstone settled the contracts on the same day and paid the amount due to the counterparties on behalf of the Company.
Under the purchase method of accounting, the purchase price is allocated to the net tangible and intangible assets based on their estimated fair values as of the date of the completion of the transaction. Such valuations require management to make significant estimates and assumptions.
F-15
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Gibson allocated the purchase price on the basis of the fair value of the underlying assets acquired and liabilities assumed as follows:
Assets | | | |
Cash and cash equivalents | | $ | 17,025 | |
Accounts receivable | | 452,260 | |
Income taxes receivable | | 4,360 | |
Inventories | | 79,000 | |
Prepaid expenses | | 6,511 | |
Long-term prepaid expenses and other assets | | 20,576 | |
Property, plant and equipment | | 605,269 | |
Intangible assets | | 179,700 | |
Goodwill | | 518,132 | |
Total assets acquired | | 1,882,833 | |
| | | |
Liabilities | | | |
Accounts payable and accrued charges | | 396,806 | |
Asset retirement obligation | | 5,853 | |
Other long-term liabilities | | 14,180 | |
Future income taxes, net | | 209,604 | |
Total liabilities assumed | | 626,443 | |
Net assets acquired | | $ | 1,256,390 | |
Customer relationships included in intangible assets were valued in groupings given the unique attributes of certain operating segments. The value was determined using an income approach and takes into account the expected revenue growth and attrition rates of customers. Using this approach, customer relationships were assigned a value of $117,000,000.
Brands included in intangible assets were valued by segment using a royalty savings method, whereby the value of the brands is estimated based upon the benefit received by the Company for owning the brands rather than paying a third party for their use. Using this approach, brands having finite lives were valued at $52,100,000.
Other intangibles include long-term customer contracts, non-compete agreements and technology patent pending, and were valued at $4,600,000, $4,400,000 and $1,600,000, respectively. These values were determined using an income approach and by estimating the benefit to the Company.
Cash, accounts receivable, accounts payable, and other current assets and liabilities were recorded at their historical carrying values, which were considered their fair values given their short-term nature.
F-16
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
3 Accounts receivable
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Trade receivables — third party | | $ | 339,519 | | $ | 283,445 | |
Allowance for doubtful accounts — third party | | (2,157 | ) | (386 | ) |
Subtotal | | 337,362 | | 283,059 | |
Risk management assets (note 20) | | 1,812 | | 752 | |
Deposits held as collateral | | — | | 20,849 | |
Broker accounts receivable | | 2,801 | | 2,649 | |
GST receivable | | 7,336 | | 8,125 | |
Other | | 5,371 | | 431 | |
Total receivables | | $ | 354,682 | | $ | 315,865 | |
A significant portion of the Company’s trade receivables are due from entities in the oil and gas industry. As of December 31, 2010, the Company had no significant concentration of credit risk; however at December 31, 2009, there was one customer that accounted for 11% of trade receivables.
Allowance for doubtful accounts
| | Successor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | |
| | | | | |
Allowance for doubtful accounts beginning balance | | $ | 386 | | $ | 352 | |
Assumed in business acquisitions | | 530 | | — | |
Additional allowances | | 1,381 | | 206 | |
Accounts receivable write off | | (140 | ) | (172 | ) |
Allowance for doubtful accounts ending balance | | $ | 2,157 | | $ | 386 | |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
4 Inventories
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Crude oil | | $ | 131,007 | | $ | 56,629 | |
Diluent | | 6,788 | | 6,257 | |
Asphalt | | 25,865 | | 23,381 | |
Natural gas liquids | | 21,000 | | 17,728 | |
Natural gas | | 20 | | 684 | |
Wellsite fluids and distillate | | 10,303 | | 7,244 | |
Spare parts and other | | 2,500 | | 1,765 | |
| | | | | |
| | $ | 197,483 | | $ | 113,688 | |
The amount of inventory included in cost of product sold, excluding depreciation and amortization, was $2,951,772,000 for 2010, $2,929,938,000 for 2009, and $108,422,000 and $4,097,797,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively. The amount of inventory written off to cost of sales, excluding depreciation and amortization, was $0 for 2010 and 2009, and $0 and $1,206,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively.
5 Long-term prepaid expenses and other assets
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Long-term prepaid expenses | | $ | 4,380 | | $ | 3,993 | |
Other assets | | 9,229 | | 972 | |
Loan to equity investee | | — | | 14,218 | |
RCA pension (note 18) | | 979 | | 787 | |
Equity investments | | 9,688 | | 10,971 | |
| | | | | |
| | $ | 24,276 | | $ | 30,941 | |
During the year ended December 31, 2009, the Company acquired a 38.86% ownership interest in Palko Environmental Ltd. (Palko), a waste management provider, for a total cost of $6,643,000. In June 2010, the Company participated in a private placement financing with Palko for $3,050,000, thereby maintaining the Company’s equity interest at 38.86%. The Company’s investment in Palko is accounted for using the equity method of accounting.
On March 10, 2008, the Company acquired a 25% ownership interest in Battle River Terminal ULC (“BRT”) for $3,750,000, which was accounted for under the equity method of accounting. As at December 31, 2009, the Company had loaned BRT a total of $14,218,000, for their capital construction program with no fixed repayment terms. On August 25, 2010, the remaining 75% of the shares of BRT were purchased by the Company and the results of BRT are consolidated from that date (note 9).
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
6 Net investment in capital leases
During the year ended December 31, 2010, the Company entered into fixed term contractual arrangements with lease terms of 12 to 20 years, to allow customers to have dedicated use of certain tanks owned by the Company. The following summarizes the Company’s net investment in these arrangements, which are accounted for as capital leases:
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Total minimum lease payments receivable | | $ | 91,956 | | $ | — | |
Unearned income | | (71,455 | ) | — | |
| | 20,501 | | — | |
Less: current portion | | 236 | | — | |
| | | | | |
Net investment in capital lease: non-current portion | | $ | 20,265 | | $ | — | |
The minimum lease receivables for the next five years are expected to be as follows:
2011 | | $ | 5,175 | |
2012 | �� | 5,175 | |
2013 | | 5,175 | |
2014 | | 5,175 | |
2015 | | 5,175 | |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
7 Property, plant and equipment
| | Successor | |
| | December 31, 2010 | |
| | Cost | | Accumulated
depreciation | | Net | |
| | | | | | | |
Land | | $ | 39,811 | | $ | 1,681 | | $ | 38,130 | |
Buildings | | 30,775 | | 6,173 | | 24,602 | |
Equipment | | 158,770 | | 28,022 | | 130,748 | |
Rolling stock | | 167,805 | | 37,321 | | 130,484 | |
Pipelines | | 126,956 | | 20,844 | | 106,112 | |
Tanks | | 201,722 | | 16,164 | | 185,558 | |
Plants | | 45,315 | | 8,064 | | 37,251 | |
| | | | | | | |
| | $ | 771,154 | | $ | 118,269 | | $ | 652,885 | |
| | Successor | |
| | December 31, 2009 | |
| | Cost | | Accumulated
depreciation | | Net | |
| | | | | | | |
Land | | $ | 41,933 | | $ | 910 | | $ | 41,023 | |
Buildings | | 28,554 | | 3,391 | | 25,163 | |
Equipment | | 123,958 | | 15,223 | | 108,735 | |
Rolling stock | | 116,010 | | 16,210 | | 99,800 | |
Pipelines | | 128,093 | | 10,998 | | 117,095 | |
Tanks | | 178,612 | | 8,640 | | 169,972 | |
Plants | | 41,002 | | 3,964 | | 37,038 | |
| | | | | | | |
| | $ | 658,162 | | $ | 59,336 | | $ | 598,826 | |
During the year ended December 31, 2010, the Company reclassified $32,600,000 of property, plant and equipment to assets held for sale, which relates to the sale of the Edmonton North Terminal on January 7, 2011 (note 27).
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
8 Intangible assets
| | Successor | |
| | December 31, 2010 | |
| | Cost | | Accumulated
amortization | | Net | |
| | | | | | | |
Technology patent pending | | $ | 1,600 | | $ | 883 | | $ | 717 | |
Brands | | 41,425 | | 9,513 | | 31,912 | |
Customer relationships | | 117,126 | | 36,434 | | 80,692 | |
Non-compete agreements | | 17,793 | | 5,859 | | 11,934 | |
Long-term customer contracts | | 32,703 | | 3,348 | | 29,355 | |
| | | | | | | |
| | $ | 210,647 | | $ | 56,037 | | $ | 154,610 | |
| | Successor | |
| | December 31, 2009 | |
| | Cost | | Accumulated
amortization | | Net | |
| | | | | | | |
Technology patent pending | | $ | 1,600 | | $ | 453 | | $ | 1,147 | |
Brands | | 41,425 | | 5,482 | | 35,943 | |
Customer relationships | | 100,603 | | 19,066 | | 81,537 | |
Non-compete agreements | | 5,796 | | 1,259 | | 4,537 | |
Long-term customer contracts | | 4,600 | | 809 | | 3,791 | |
| | | | | | | |
| | $ | 154,024 | | $ | 27,069 | | $ | 126,955 | |
The intangible assets are being amortized over a weighted-average period of approximately 8 years, ending 2024.
Amortization expense for the next five years is expected to be as follows:
2011 | | $ | 31,771 | |
2012 | | 26,902 | |
2013 | | 21,764 | |
2014 | | 20,997 | |
2015 | | 18,526 | |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
The amortization expense recorded for intangible assets was $29,177,000 for 2010, $25,747,000 for 2009, $1,323,000 and $3,109,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively.
Intangible assets are reviewed for impairment whenever events or conditions indicate that their net carrying amount may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset’s fair value is recognized during the period, with a charge to earnings. No impairment was recorded in the year ended December 31, 2010. As a result of a general market downturn and increased competition in the truck transportation segment, during the fourth quarter of 2009, conditions indicated that the net carrying value of intangible assets within this segment would not be recoverable. Therefore, intangible assets within the truck transportation segment were tested for impairment. The tests indicated that customer relationships and brands were impaired. The Company recorded a $28,645,000 impairment relating to customer relationships and brands within the truck transportation segment in the year ended December 31, 2009. The Company used an income approach to determine the fair value of its customer relationships. The approach takes into account the expected revenue growth and attrition rates of customers. The Company used a royalty savings approach to determine the fair value of its brands. The value of the brands was estimated based upon the benefit received by the Company for owning the brands rather than paying a third party. No impairment was recorded in the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008.
9 Business acquisitions
Battle River Terminal ULC (“BRT”)
On August 25, 2010, the Company completed the acquisition of 75% of the common shares of BRT for cash, net of cash acquired, of $54,849,000. Prior to the acquisition, the Company had a 25% ownership interest in BRT, which was accounted for using the equity method of accounting. The carrying value of the original investment in the common shares on the acquisition date was $3,620,000. BRT is comprised of four storage tanks and related infrastructure that are connected to the Company’s Hardisty Terminal. 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 | | $ | 72,112 | |
Accounts receivable | | 638 | |
Prepaid expenses | | 16 | |
Accounts payable and accrued charges | | (588 | ) |
Other long-term liabilities | | (308 | ) |
| | | |
Net assets acquired | | 71,870 | |
Less: | | | |
Loan due to subsidiary | | (13,401 | ) |
Investment amount | | (3,620 | ) |
Net cash paid | | $ | 54,849 | |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Taylor Companies
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 $153,194,000. 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 the Company’s 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 | | $ | 42,231 | |
Accounts receivable | | 18,896 | |
Inventories | | 4,505 | |
Prepaid expenses | | 1,365 | |
Goodwill | | 59,733 | |
Intangible assets (1) | | 50,012 | |
Accounts payable and accrued charges | | (22,881 | ) |
Other long-term liabilities | | (667 | ) |
| | | |
Net assets acquired | | $ | 153,194 | |
(1) Consists of long-term customer contracts of $29,228,000, customer relationships of $15,222,000 and a non-compete agreement of $5,562,000.
The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.
Aarcam Propane & Construction Heat Ltd.
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 will further expand the Company’s market presence and provide the Company with an expanded client base. This acquisition was accounted for using the purchase method with the results from operations included in these financial statements from the date of acquisition.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
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 non-compete agreement of $648,000 and customer relationships of $174,000.
The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.
Johnstone Tank Trucking Ltd.
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 the Company’s market presence and provide access to activity related to the Bakken oilfields. This acquisition was accounted for using the purchase method with the results from operations included in these financial statements from the date of acquisition.
The net assets acquired have been recorded as follows:
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 non-compete agreement of $6,042,000 and customer relationships of $1,645,000.
The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Superior Propane
On November 18, 2009, the Company purchased three propane terminal facilities and associated business located in Montana and South Dakota, from Superior Propane LLC for cash of $6,657,000. This acquisition further expands the Company’s market presence and customer base in the wholesale propane market. 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 | | $ | 5,302 | |
Inventory | | 35 | |
Goodwill (1) | | 525 | |
Intangible assets (2) | | 795 | |
| | | |
Net assets acquired | | $ | 6,657 | |
(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.
The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.
Turner Gas
On July 1, 2009, the Company purchased the wholesale propane business and assets of the Washington and Oregon operations of Turner Gas for cash of $1,608,000. The acquisition further expands the Company’s market presence and together with current infrastructure, it will provide opportunities for further expansion. 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 | | $ | 1,383 | |
Intangible assets (1) | | 225 | |
| | | |
Net assets acquired | | $ | 1,608 | |
(1) Consists of a non-compete agreement.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Bridge Creek Trucking Ltd.
On May 1, 2009, the Company purchased 100 percent of the common shares of Bridge Creek Trucking Ltd. for cash, net of cash acquired, of $6,900,000. This acquisition expands the Company’s market presence in Southern Saskatchewan. 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 | | $ | 4,861 | |
Accounts receivable | | 1,775 | |
Inventory | | 161 | |
Prepaid expenses | | 133 | |
Other assets | | 25 | |
Goodwill (1) | | 707 | |
Intangible assets (2) | | 1,950 | |
Accounts payable and accrued charges | | (1,778 | ) |
Future income taxes | | (934 | ) |
| | | |
Net assets acquired | | $ | 6,900 | |
(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.
The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.
Chief Hauling Contractors Inc.
On June 1, 2008, the Company purchased 100 percent of the common shares of Chief Hauling Contractors Inc. for cash of $14,430,000. This acquisition expands the Company service offering within the truck transportation segment. 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 | | $ | 6,556 | |
Accounts receivable and other assets | | 2,330 | |
Goodwill (1) | | 4,733 | |
Intangible assets | | 3,350 | |
Future income taxes | | (2,539 | ) |
| | | |
Net assets acquired | | $ | 14,430 | |
(1) The amount of purchased goodwill is not expected to be deductible for tax purposes.
The goodwill is attributable to the synergies expected to be achieved from integrating the acquired company into the Company’s existing business.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
10 Goodwill
The changes in the carrying amount of goodwill are as follows:
| | Successor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | |
| | | | | |
Opening balance | | $ | 433,894 | | $ | 518,132 | |
Impairment | | — | | (85,470 | ) |
Additions (note 9) | | 67,249 | | 1,232 | |
Effect of changes in foreign exchange rates | | (2,326 | ) | — | |
| | | | | |
Closing balance | | $ | 498,817 | | $ | 433,894 | |
Goodwill represents the excess of the purchase price paid by Gibson over the fair value assigned to the net assets of the Company on the date of the Acquisition plus the goodwill arising on acquisitions since that date.
No impairment was recorded in the year ended December 31, 2010. However, in the year ended December 31, 2009, when the Company carried out its annual 2009 impairment test, it was determined that the goodwill in the truck transportation segment was impaired by $85,470,000. The impairment loss, which was recognized in the fourth quarter of 2009, was determined by calculating the fair value of the truck transportation reporting unit based on values of comparable businesses and comparing it to the reporting unit’s book value. The impairment within this segment was largely as a result of a general market downturn and increased competition in the truck transportation segment. No impairment was recorded in the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
11 Accounts payable and accrued charges
Accounts payable and accrued charges include the following items:
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Accounts payable — trade | | $ | 294,624 | | $ | 215,047 | |
Accrued compensation charges | | 11,736 | | 8,400 | |
GST payable | | 1,245 | | 862 | |
Risk management liabilities (note 20) | | 3,252 | | 3,565 | |
Interest payable | | 14,910 | | 6,000 | |
Due to Hunting (note 22) | | 53,568 | | 3,215 | |
Other | | 14,351 | | 17,780 | |
| | | | | |
| | $ | 393,686 | | $ | 254,869 | |
12 Asset retirement obligation
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of terminal sites, asphalt refinery and fractionation plant:
| | Successor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | |
| | | | | |
Opening balance | | $ | 8,287 | | $ | 5,875 | |
Change in estimated future cash flows | | — | | 1,794 | |
Assumed in business acquisitions | | 975 | | — | |
Accretion expense | | 608 | | 618 | |
Effect of changes in foreign exchange rates | | (26 | ) | — | |
Reclassified to liabilities related to assets held for sale | | (230 | ) | — | |
| | | | | |
Closing balance | | $ | 9,614 | | $ | 8,287 | |
The Company currently estimates the total undiscounted amount, including an inflation factor, of estimated cash flows to settle the future liability for asset retirement obligation to be approximately $81,574,000 and $68,467,000 at December 31, 2010 and December 31, 2009, respectively. 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.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
13 Credit facilities
On December 12, 2008, concurrent with the Acquisition (note 2), the Company established a revolving credit facility of up to U.S.$65,000,000 (the “Credit 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. On September 17, 2010, the Company increased its maximum amount to U.S.$200,000,000, of which up to U.S.$30,000,000 is available to subsidiaries with collateral assets located in the United States.
The Credit facility has a term of four years expiring on December 12, 2012. Borrowings under the Credit facility bear interest at a rate equal to, at the Company’s option, either at LIBOR, the lenders prime rate, the Bankers Acceptance rate or the Above Bank Rate, plus an applicable margin based on a pricing grid. The Company has drawn $43,500,000 and $25,000,000 against the Credit facility, as at December 31, 2010 and 2009, respectively. In addition, the Company has issued Letters of Credit totalling $59,242,000 and $9,800,000 as at December 31, 2010 and 2009, respectively.
Any borrowings under the Credit facility are secured by the Company’s current assets, including, but not limited to, inventory and accounts receivable.
At December 31, 2010 and 2009, the Company had restricted cash of $6,137,000 and $9,754,000, respectively. The cash is restricted because it has been posted as collateral for certain of the Company’s marketing activities.
14 Long-Term Debt
Long-term debt consists of the following:
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
First Lien Senior Secured Notes | | $ | 556,976 | | $ | 586,096 | |
Senior Notes | | 198,920 | | — | |
Debt issue costs and debt discount | | (37,742 | ) | (32,154 | ) |
| | $ | 718,154 | | $ | 553,942 | |
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, payable semi-annually on June 1 and December 1 of each year. The proceeds from the First Lien Notes were used to repay the Bridge Loans in full. 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. Any prepayments made up to May 31, 2013 would be at a premium. All
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
borrowings under the First Lien Notes are collateralized by substantially all of the Company’s property, plant 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, payable semi-annually on July 15 and January 15 of each year. Throughout the term of the Senior Notes and under certain conditions, the Company has the option to prepay the principal on the Senior Notes. Any prepayment made up to January 14, 2017 would be at a premium.
The effective interest rate on the long-term debt, excluding the accretion of debt issuance costs, was 10.91% and 10.78% for the year ended December 31, 2010 and December 31, 2009, respectively, and 10.62% for the period from December 13, 2008 to December 31, 2008.
In the year ended December 31, 2009, as a result of the repayment of the Bridge Loans, the Company recognized a loss on settlement of $18,517,000 as debt extinguishment costs.
At December 31, 2010, future scheduled principal payments on long-term debt are as follows (in U.S. dollars):
2011 | | $ | — | |
2012 | | — | |
2013 | | — | |
2014 | | 560,000 | |
2015 | | — | |
2016 and after | | 200,000 | |
Total | | $ | 760,000 | |
15 Other long-term liabilities
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Remediation liability | | $ | 12,431 | | $ | 13,015 | |
Post-retirement benefits (note 18) | | 2,878 | | 2,642 | |
Accrued pension liability (note 18) | | 346 | | 435 | |
| | $ | 15,655 | | $ | 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.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
16 Related party transactions
Successor
As part of the capitalization of the Company, Riverstone contributed to the Company certain foreign exchange contracts with a negative value of $169,049,000. Subsequent to contributing the contracts, Riverstone settled the contracts and paid the amount due to the counterparties on behalf of the Company. These transactions were recorded as a non-cash equity distribution and contribution, respectively, to and from Riverstone and had zero net effect on the company’s equity in the period from December 13, 2008 to December 31, 2008.
On December 12, 2008, the Company entered into a Management Agreement with Riverstone. Under the Management Agreement, the Company engaged Riverstone to provide management advisory services in connection with the general business operations of the Company. Total management fees and expenses recognized for the year ended December 31, 2010 and 2009 were $1,042,000 and $1,037,000, respectively, and for the period December 13, 2008 to December 31, 2008 were $52,000. These amounts are included in the General and administrative expenses on the statement of income.
In connection with the Acquisition, the Company paid to Riverstone approximately $15,375,000 relating to transactional fees and expenses, which have been included in the direct costs of the Acquisition.
With respect to companies that Riverstone has a controlling interest or has significant influence on, in the years ended December 31, 2010 and 2009, the Company recognized revenue of $4,471,000 and $21,000 respectively, and purchased product and services of $25,445,000 and $117,000, respectively. There were no material transactions in the period from December 13, 2008 to December 31, 2008.
In October 2009, two members of senior management began serving as members of the board of directors of Palko Environmental Ltd (“Palko”), formerly known as Deepwell Energy Services Trust. 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 years ended December 31, 2010 and December 31, 2009, the Company recognized revenue of $167,000 and $30,000, respectively. In the years ended December 31, 2010 and December 31, 2009, the Company purchased product from Palko of $3,506,000 and $1,700,000, respectively. In addition, on June 30, 2010, the Company participated in a private placement financing with Palko for $3,050,000 that allowed the Company to maintain its approximate 39% equity interest in Palko.
The related party transactions noted above have been measured at exchange amounts.
Predecessor
Prior to the Acquisition, the Company borrowed an amount of $157,000,000 from Riverstone, which was used to repay a loan outstanding to an affiliate of Hunting just prior to the Acquisition.
As at December 12, 2008, an amount of $157,000,000 was due to an affiliate of Hunting, Hunting Knightsbridge Holdings Ltd. Prior to the Acquisition, this amount was repaid in full. Interest on the loans was $8,280,000 for the period January 1, 2008 to December 12, 2008. This amount is included in the interest due to affiliates on the statement of income.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
H.G. Management Services Ltd., an affiliate of Hunting, charged management fees amounting to $1,692,000 for the period January 1, 2008 to December 12, 2008. The amount is included in the general and administrative expenses on the statement of income.
The related party transactions noted above have been measured at exchange amounts.
17 Income taxes
The income tax provision differs from the amounts, which would be obtained by applying the combined Canadian base federal and provincial income tax rate to income before income taxes. These differences result from the following items:
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Period from
December 13,
2008 to
December 31,
2008 | | Period from
January 1,
2008 to
December 12,
2008 | |
| | | | | | | | | |
Income (loss) before income taxes | | $ | (13,191 | ) | $ | (75,598 | ) | $ | 6,010 | | $ | 86,517 | |
Statutory income tax rate | | 28.00 | % | 29.00 | % | 29.50 | % | 29.50 | % |
Computed income tax provision (recovery) | | (3,693 | ) | (21,923 | ) | 1,773 | | 25,522 | |
Increase (decrease) in income tax resulting from: | | | | | | | | | |
Goodwill impairment, net of tax | | — | | 24,786 | | — | | — | |
Unrealized foreign exchange gain | | (4,732 | ) | (5,310 | ) | (738 | ) | — | |
Realized foreign exchange gain | | (1,021 | ) | (8,898 | ) | — | | | |
Non-deductible expenses | | 190 | | 237 | | — | | 734 | |
Stock based compensation | | 1,296 | | 2,598 | | — | | — | |
Rate differential on foreign taxes | | (1,038 | ) | — | | — | | — | |
Non-taxable dividends | | (2,083 | ) | — | | — | | — | |
Investment tax credits used | | — | | — | | — | | 294 | |
Other, including revisions in previous tax estimates | | 444 | | (3,231 | ) | 73 | | 1,288 | |
Rate reductions applied to future income tax liabilities | | — | | — | | — | | (1,460 | ) |
Rate reduction due to partnership deferral | | (2,709 | ) | (908 | ) | (78 | ) | (1,179 | ) |
| | $ | (13,346 | ) | $ | (12,649 | ) | $ | 1,030 | | $ | 25,199 | |
| | | | | | | | | |
Income tax provision (recovery) | | | | | | | | | |
Current | | $ | 2,779 | | $ | (226 | ) | $ | 280 | | $ | 33,981 | |
Future | | (16,125 | ) | (12,423 | ) | 750 | | (8,782 | ) |
| | $ | (13,346 | ) | $ | (12,649 | ) | $ | 1,030 | | $ | 25,199 | |
| | | | | | | | | |
Effective income tax rate | | 101.18 | % | 16.73 | % | 17.14 | % | 29.13 | % |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
The tax effects of the significant components of temporary differences that give rise to future income tax assets and liabilities are as follows:
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Future income tax assets: | | | | | |
| | | | | |
Non-capital losses carried forward | | $ | 8,042 | | $ | 1,509 | |
Other items | | 1,222 | | 410 | |
Asset retirement obligations, net | | 3,628 | | 4,340 | |
Post-retirement benefits and pension plan accruals | | 530 | | 475 | |
| | 13,422 | | 6,734 | |
Less current portion | | — | | 1,509 | |
| | | | | |
| | $ | 13,422 | | $ | 5,225 | |
| | | | | |
Future income tax liabilities: | | | | | |
| | | | | |
Timing of partnership income recognition and related items | | $ | 47,890 | | $ | 46,145 | |
Property, plant and equipment | | 102,649 | | 112,201 | |
Differences between accounting and tax bases of assets and liabilities | | 31,542 | | 42,005 | |
Other items | | 14,536 | | 4,861 | |
| | 196,617 | | 205,212 | |
Less current portion | | 177 | | 839 | |
| | | | | |
| | 196,440 | | 204,373 | |
| | | | | |
Net future income tax liability | | $ | 183,195 | | $ | 198,478 | |
Income tax losses carry forward
At December 31, 2010 and December 31, 2009, the Company had losses available to offset future income for tax purposes of $22,942,000 and $5,624,000, respectively. The losses expire as follows:
December 31, 2028 | | $ | 2,689 | |
December 31, 2030 | | 20,253 | |
| | $ | 22,942 | |
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Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
18 Pension plans
Defined benefit pension plans
In the valuation of pension and other post retirement benefits (“OPRB”), management utilizes various assumptions. The Company determines its discount rate based on an investment grade bond yield curve with a duration that approximates the benefit payment timing of each plan. This rate can fluctuate based on changes in investment grade bond yields.
The long-term rate of return on plan assets is estimated based on an evaluation of historical returns for each asset category held by the plans, coupled with the current and short-term mix of the investment portfolio. The historical returns are adjusted for expected future market and economic changes. This return will fluctuate based on actual market returns and other economic factors.
The rate of future health care cost increases is based on historical claims and enrolment information projected over the next fiscal year and adjusted for administrative charges. Future compensation rates, withdrawal rates and participant retirement age are determined based on historical information. These assumptions are not expected to significantly change. Mortality rates are determined based on a review of published mortality tables.
The Company’s defined benefit plans are funded based upon the advice of independent actuaries. The pension expense recorded was $257,000 and $297,000 for the year ended December 31, 2010 and 2009, respectively, and $41,000 and $1,456,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively. Funding of the defined benefit plans was $346,000 for the year ended December 31, 2010, $750,000 for the year ended December 31, 2009 and $10,000 and $1,485,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively. As part of the purchase accounting in connection with the Acquisition (note 2), the Company recorded an additional liability of $4,300,000 relating to the projected benefit obligations for one of the defined benefit plans in place at the time of the Acquisition.
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Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
The Company is required to file an actuarial valuation of its pension plans with the provincial regulator every three years. The most recent actuarial valuation filing was dated December 31, 2009. Based on the most recent actuarial valuation as at December 31, 2010, the status of the plans was as follows:
Accrued benefit obligation
| | Successor | |
| | Year ended
December 31, 2010 | | Year ended
December 31, 2009 | |
| | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | |
| | | | | | | | | |
Accrued benefit obligation, beginning of period | | $ | 11,725 | | $ | 3,092 | | $ | 24,771 | | $ | 2,530 | |
Current service cost | | 176 | | 211 | | 233 | | 248 | |
Interest cost | | 569 | | 173 | | 586 | | 182 | |
Benefits paid | | (417 | ) | (265 | ) | (15,588 | ) | (324 | ) |
Actuarial loss (gain) | | 726 | | (107 | ) | 2,118 | | 1,261 | |
Other | | (710 | ) | 125 | | (395 | ) | (805 | ) |
Accrued benefit obligation, end of period | | $ | 12,069 | | $ | 3,229 | | $ | 11,725 | | $ | 3,092 | |
Plan assets
| | Successor | |
| | Year ended
December 31, 2010 | | Year ended
December 31, 2009 | |
| | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | |
| | | | | | | | | |
Fair value of pension plan assets, beginning of period | | $ | 10,514 | | $ | — | | $ | 15,765 | | $ | — | |
Actual return on plan assets and expected interest | | 590 | | — | | 521 | | — | |
Actual and expected contributions | | 379 | | 265 | | 555 | | 203 | |
Actual and expected benefits paid | | (417 | ) | (265 | ) | (6,330 | ) | (203 | ) |
Actuarial loss (gain) | | (507 | ) | — | | 3 | | — | |
Fair value of pension plan assets, end of period | | $ | 10,559 | | $ | — | | $ | 10,514 | | $ | — | |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Accrued benefit asset (liability)
| | Successor | |
| | December 31, 2010 | | December 31, 2009 | |
| | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | |
| | | | | | | | | |
Funded status | | $ | (1,510 | ) | $ | (3,229 | ) | $ | (1,211 | ) | $ | (3,092 | ) |
Amounts not recognized: | | | | | | | | | |
Unamortized net actuarial loss | | 2,143 | | 1,078 | | 1,563 | | 1,255 | |
Unamortized past service cost | | — | | (727 | ) | — | | (805 | ) |
Accrued benefit asset (liability) | | $ | 633 | | $ | (2,878 | ) | $ | 352 | | $ | (2,642 | ) |
| | Successor | |
| | December 31, 2010 | | December 31, 2009 | |
| | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | |
| | | | | | | | | |
Funded status | | | | | | | | | |
Amounts recognized in the balance sheet consist of: | | | | | | | | | |
Long-term prepaid benefit | | $ | 979 | | $ | — | | $ | 787 | | $ | — | |
Accrued pension and other post retirement benefits | | (346 | ) | (2,878 | ) | (435 | ) | (2,642 | ) |
Net amount recognized | | $ | 633 | | $ | (2,878 | ) | $ | 352 | | $ | (2,642 | ) |
Prepaid pension and other post retirement benefits are included in long-term prepaid expenses and other assets. Accrued benefit obligations are included in other long-term liabilities.
The significant weighted average actuarial assumptions adopted in measuring the Company’s accrued benefit obligation are as follows:
| | 2010 | | 2009 | | 2008 | |
| | | | | | | |
Discount rate | | 5.0 | % | 5.25 | % | 7.0 | % |
Expected long-term rate of return on plan assets | | 6.5 | % | 6.25-7.0 | % | 3.5 — 7.0 | % |
Rate of compensation increase | | 3.0 | % | 4.0 | % | 4.0 — 4.5 | % |
The expected long-term return on assets represents the average rate of earnings expected on the pension fund, net of expenses, to provide for the benefits included in the accrued benefit obligation. It is used to calculate the expected return on pension fund assets, which is a component of the pension expense. For purposes of the December 31, 2010 valuation, the expected rate of return on pension fund assets after taking account of investment and routine administrative expenses, is assumed to be 6.5% for the plans.
The difference in present values of pension fund assets and accrued pension benefits is amortized to income over the expected average remaining service life of the employees covered by the plans.
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
The periodic expense for the benefits is as follows:
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Period from
December 13, 2008
to December 31,
2008 | | Period from
January 1, 2008
to December 12,
2008 | |
| | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | |
| | | | | | | | | | | | | | | | | |
Current service cost | | $ | 176 | | $ | 211 | | $ | 233 | | $ | 248 | | $ | 22 | | $ | 16 | | $ | 934 | | $ | 233 | |
Interest cost | | 569 | | 173 | | 586 | | 182 | | 48 | | 16 | | 958 | | 153 | |
Actual return on plan assets | | (634 | ) | — | | (1,077 | ) | — | | (234 | ) | — | | 1,971 | | — | |
Actuarial loss (gain) on accrued benefit obligation | | 726 | | (107 | ) | 2,118 | | 1,261 | | (1 | ) | — | | (1,008 | ) | (574 | ) |
Plan amendments | | — | | — | | — | | (805 | ) | — | | — | | — | | — | |
Difference between actual and: | | | | | | | | | | | | | | | | | |
Expected return on plan assets | | 44 | | — | | 555 | | — | | 193 | | — | | (2,723 | ) | — | |
Recognized actuarial gain (loss) | | (624 | ) | 177 | | (2,118 | ) | (1,255 | ) | 11 | | — | | 1,017 | | — | |
Difference between amortization of past service costs and actual plan amendments | | — | | (78 | ) | — | | 805 | | 2 | | — | | 464 | | — | |
Amortization of transitional obligation | | — | | — | | — | | — | | — | | — | | (157 | ) | — | |
Defined benefit plan expense | | $ | 257 | | $ | 376 | | $ | 297 | | $ | 436 | | $ | 41 | | $ | 32 | | $ | 1,456 | | $ | (188 | ) |
The average remaining service period of the active employees covered by the defined benefit plan is 5.3 years.
Assumed health care cost trends rates are as follows:
| | December 31,
2010 | | December 31,
2009 | |
| | | | | |
Health care cost trend rate for next year | | 8.0 | % | 8.0 | % |
Rate that the trend rate gradually trends to | | 5.0 | % | 5.0 | % |
Year that the trend rate reaches the rate which it is expected to remain at | | 2013 | | 2013 | |
Assumed health care cost trend rates have an effect on the amounts reported for the pension plans. A one-percentage point change in assumed health care cost trend rates would have the following impact:
| | One % point
increase | | One % point
decrease | |
| | | | | |
Effect on total of service cost and interest cost | | $ | 68 | | $ | (53 | ) |
Effect on post retirement benefit obligation | | 368 | | (296 | ) |
| | | | | | | |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
The Company’s pension plan asset allocation is as follows:
Asset category
| | % of Plan Assets as at: | |
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
| | Defined
benefit | | Defined
benefit | |
| | | | | |
Equity | | 59.1 | | 59.8 | |
Bonds | | 32.9 | | 33.4 | |
Real estate and other | | 3.0 | | 2.9 | |
Cash and equivalents | | 5.0 | | 3.9 | |
Total | | 100.0 | | 100.0 | |
The Company’s overall investment strategy is to achieve an asset mix to meet both near-term and long term benefit payments with a diversification of asset types. The fair value of the Company’s plan assets are determined by using Level 1 inputs, defined as observable inputs such as quoted prices in active markets.
The Company’s contributions to the pension plans are subject to the results of actuarial valuation. Contributions by participants to the pension and other benefits plan were $17,500 (2009- $28,920).
Estimated future payments under the plan are as follows:
| | Defined
benefit | | OPRB | |
| | | | | |
2011 | | $ | 425 | | $ | 298 | |
2012 | | 436 | | 259 | |
2013 | | 500 | | 261 | |
2014 | | 543 | | 225 | |
2015 | | 612 | | 206 | |
2016 - 2020 | | 3,433 | | 1,018 | |
Total | | $ | 5,949 | | $ | 2,267 | |
Defined contribution pension plan
The total expense recorded for the defined contribution pension plans was $3,270,000 and $3,004,000 for 2010 and 2009, $132,000, and $2,525,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively.
Accumulated benefit obligation
| | Successor | |
| | December 31, 2010 | | December 31, 2009 | |
| | Defined
benefit | | OPRB | | Defined
benefit | | OPRB | |
| | | | | | | | | |
Accumulated benefit obligation | | $ | 11,917 | | $ | 3,230 | | $ | 11,189 | | $ | 3,218 | |
| | | | | | | | | | | | | |
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Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
19 Stock based compensation plan
Successor
During the year ended December 31, 2009, the Board of Directors adopted the Equity Incentive Plan (the “Plan”) that provides for the issuance of stock options, stock appreciation rights, restricted stock and restricted stock units to employees, directors, consultants, and other associates. The Company reserved a total of 59,739 shares for grants under the Plan. As of December 31, 2010, the Company has only issued stock options to employees participating in the Plan. The options generally vest in equal tranches annually over a period of five years from the date of grant and have a maximum term of ten years. The Company has granted both traditional time-vesting stock options and performance vesting stock options under the Plan. The performance vesting stock options vest and expire under the same terms and service conditions as the time-vesting stock options, with vesting subject to the Company attaining prescribed performance relative to predetermined key financial measures.
The compensation expense charged to operations was $4,629,000 and $8,957,000 for the year ended December 31, 2010 and 2009, respectively. 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. The weighted-average fair value per stock option granted in the year ended December 31, 2010 and 2009 was $373 and $360, respectively.
A summary of activity under the Plan is set forth below.
| | Options Outstanding | |
| | Options
Available for
Grant | | Numbers of
Shares | | Weighted-
Average
Exercise Price
(in dollars) | |
Balance at inception | | 59,739 | | — | | $ | — | |
Granted | | (54,550 | ) | 54,550 | | 1,000 | |
| | | | | | | |
Balance at December 31, 2009 | | 5,189 | | 54,550 | | 1,000 | |
| | | | | | | |
Granted | | (4,900 | ) | 4,900 | | 1,000 | |
Forfeited | | 1,936 | | (1,936 | ) | 1,000 | |
| | | | | | | |
Balance at December 31, 2010 | | 2,225 | | 57,514 | | $ | 1,000 | |
As of December 31, 2010, no options have been exercised since the inception of the Plan. At December 31, 2010 and 2009, total outstanding options vested under the Plan were 15,356 and 9,546, respectively at a weighted-average exercise price of $1,000.
Additional information under the Plan regarding options outstanding as of December 31, 2010 is as follows:
| | Outstanding | | Exercisable | |
Range of
Exercise
Prices
(in dollars) | | Number
Outstanding | | Weighted
Average
Remaining
Contractual
Life (Years) | | Weighted-
Average
Exercise
Price
(in dollars) | | Aggregate
Intrinsic
Value
(in dollars) | | Number
Outstanding | | Weighted-
Average
Remaining
Contractual
Life (Years) | | Weighted-
Average
Exercise
Price
(in dollars) | | Aggregate
Intrinsic
Value
(in dollars) | |
$ | 1,000 | | 57,514 | | 8.9 | | $ | 1,000 | | $ | 21,050,000 | | 15,356 | | 9.0 | | $ | 1,000 | | $ | 5,620,000 | |
| | | | | | | | | | | | | | | | | | | | | | |
F-39
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
A summary of the Company’s outstanding nonvested options under the Plan are as follows:
| | Number of
Shares | | Weighted-
Average
Grant date
Fair Value
(in dollars) | |
Granted | | 54,550 | | $ | 360 | |
Vested | | (9,546 | ) | 360 | |
Nonvested at December 31, 2009 | | 45,004 | | 360 | |
| | | | | |
Granted | | 4,900 | | 373 | |
Vested | | (5,810 | ) | 361 | |
Forfeited | | (1,936 | ) | 360 | |
Nonvested at December 31, 2010 | | 42,158 | | $ | 361 | |
As of December 31, 2010, there was $7,171,000 of total unrecognized compensation cost related to nonvested awards. The total fair value of options vested during the year ended December 31, 2010 was $2,101,000.
The options were valued using the weighted-average assumptions noted below:
| | Year ended
December 31, | | Year ended
December 31, | |
| | 2010 | | 2009 | |
Expected dividend rate | | 0.0 | % | 0.0 | % |
Expected volatility | | 29.8 | % | 29.4 | % |
Risk-free interest rate | | 3.3 | % | 2.8 | % |
Expected life of option (years) | | 6.5 | | 6.5 | |
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable and it requires the input of highly subjective assumptions. Expected volatility of the stock is based on comparable companies in the industry because the Company does not have historical volatility data for its own stock. The expected term of options represents the period of time that options granted are expected to be outstanding. The risk-free rate is based on the Government of Canada’s Canadian Bond Yields with a remaining term equal to the expected life of the options used in the Black-Scholes valuation model. In the future, as the Company gains historical data for volatility in its own stock and the actual term over which employees hold its options, expected volatility and expected term may change, which could substantially change the grant-date fair value of future awards of stock options and, ultimately, the expense the Company records.
Predecessor
Prior to the Acquisition, the Predecessor Company’s parent, Hunting, operated a Hunting Unapproved Share Option Plan, which granted common share options, exercisable into common shares of Hunting, to eligible employees. The vesting of options granted were subject to the achievement of performance targets over a three-year period. Thereafter, the employee, subject to continued employment, had seven years in which to exercise the options. The Predecessor Company made a cash payment to Hunting in an amount that was
F-40
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
equivalent to the amount of stock based compensation expense allocated to it during the period. In connection with the Acquisition, all options that were unvested were cancelled and no new options were granted to employees under this plan after the Acquisition date. All outstanding and exercisable options outstanding on the Acquisition date were exercisable within one year, with any unexercised options being cancelled after that date.
The expense recognized relating to the Hunting Unapproved Share Option Plan was $1,801,000 for the period from January 1, 2008 to December 12, 2008. No expense was required after December 12, 2008 as the amounts were fully vested at that date.
In addition, Hunting operated a Long Term Incentive Plan (“LTIP”) that provided for rewards that could be settled either in Hunting stock or cash. Executives were invited to participate in the Company’s LTIP, with the rewards subject to performance conditions.
The LTIP was a performance-linked plan with an incentive pool calculated using the sum of the Group’s after tax operating income after deducting a charge for the after tax cost of capital at a rate of 7% on average shareholders’ funds. The incentive had two components, the first being 2% of the absolute value added, and the second being 5% of the incremental value added. Awards were determined for each participant at the beginning of a three-year performance cycle and were settled at the end of each cycle.
Rewards were based on performance related criteria and once granted, were paid at the end of a three-year period. The Company made a cash payment to the Company’s parent equivalent to the amount of LTIP awards expensed during the year.
The expense recognized attributable to LTIP was $5,290,000 for the period from January 1, 2008 to December 12, 2008. Benefits under the LTIP were accelerated on the Acquisition, and therefore no expense was recorded for the Hunting LTIP after December 12, 2008.
20 Financial instruments
The Company has financial instruments other than financial contracts consisting of cash and cash equivalents, accounts receivable, accounts payable, credit facility and long-term debt. With the exception of long-term debt, 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 December 31, 2010, based on market information, was U.S. $821,800,000.
The fair value of risk management assets and liabilities were as follows:
| | | | | | Successor | |
| | | | | | December 31,
2010 | | December 31,
2009 | |
Financial Assets | | | | | | | | | |
| | Held for Trading | | Risk Management Assets | | $ | 1,812 | | $ | 752 | |
| | | | | | | | | |
Financial Liabilities | | | | | | | | | |
| | Held for Trading | | Risk Management Liabilities | | $ | 3,252 | | $ | 3,565 | |
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Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Fair value measures
The Company’s derivatives 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 December 31, 2010 was:
| | Total | | Level 1 | | Level 2 | | Level 3 | |
Assets from commodity derivative contracts | | | | | | | | | |
Commodity swaps | | $ | 1,029 | | $ | — | | $ | 1,029 | | $ | — | |
Foreign currency forward contracts | | 783 | | — | | 783 | | — | |
Total assets | | $ | 1,812 | | $ | — | | $ | 1,812 | | $ | — | |
| | | | | | | | | |
Liabilities from commodity derivative contracts | | | | | | | | | |
Commodity futures | | $ | 1,599 | | $ | 1,599 | | $ | — | | $ | — | |
Commodity swaps | | 122 | | — | | 122 | | — | |
Electricity swaps | | 1,463 | | — | | 1,463 | | — | |
Foreign currency forward contracts | | 68 | | — | | 68 | | — | |
Total liabilities | | $ | 3,252 | | $ | 1,599 | | $ | 1,653 | | $ | — | |
The fair value of derivative contracts at December 31, 2009 was:
| | Total | | Level 1 | | Level 2 | | Level 3 | |
Assets from commodity derivative contracts | | | | | | | | | |
Commodity futures | | $ | 8 | | $ | 8 | | $ | — | | $ | — | |
Commodity swaps | | 157 | | — | | 157 | | — | |
Foreign currency forward contracts | | 587 | | — | | 587 | | — | |
Total assets | | $ | 752 | | $ | 8 | | $ | 744 | | $ | — | |
| | | | | | | | | |
Liabilities from commodity derivative contracts | | | | | | | | | |
Commodity futures | | $ | 1,453 | | $ | 1,453 | | $ | — | | $ | — | |
Electricity swaps | | 2,112 | | — | | 2,112 | | — | |
Total liabilities | | $ | 3,565 | | $ | 1,453 | | $ | 2,112 | | $ | — | |
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
The following is a summary of the Company’s risk management contracts outstanding, along with their carrying value and fair value at December 31, 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 | |
| | | | | | | | | |
January 2011 | | Bought Futures | | 75 | | $ | 90.46 | | | |
January 2011 — February 2011 | | Sold Futures | | 720 | | 89.14 | | | |
| | | | | | | | $ | (1,599 | ) |
| | | | | | | | | | | |
ClearPort-WTI to Mt. Belvieu Propane Swaps
Term | | Contract | | Volume
(bbls) | | U.S.$/bbl | | Fair Value | |
| | | | | | | | | |
January 2011 — December 2011 | | Sold WTI | | 5 | | $ | 83.77 | | | |
| | Bought Propane | | 10 | | 40.95 | | | |
April 2011 — September 2011 | | Bought WTI | | 5 | | 77.31 | | | |
| | Sold Propane | | 10 | | 39.59 | | | |
| | | | | | | | $ | 532 | |
| | | | | | | | | | | |
ClearPort-Conway to Mt. Belvieu Butane Swap
Term | | Contract | | Volume
(bbls) | | U.S.$/bbl | | Fair Value | |
| | | | | | | | | |
January 2011 — February 2011 | | Bought Conway | | 10 | | $ | 70.56 | | | |
| | Sold Belvieu | | 10 | | 71.82 | | | |
| | | | | | | | $ | (17 | ) |
| | | | | | | | | | | |
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
ClearPort-WTI to Mt. Belvieu Butane Swaps
Term | | Contract | | Volume
(bbls) | | U.S.$/bbl | | Fair Value | |
| | | | | | | | | |
January 2011 — February 2011 | | Sold WTI | | 16 | | 89.52 | | | |
| | Bought Butane | | 20 | | 71.76 | | | |
January 2011 — February 2011 | | Sold WTI | | 16 | | 89.84 | | | |
| | Bought Butane | | 20 | | 71.87 | | | |
January 2011 — December 2011 | | Sold WTI | | 10 | | 78.40 | | | |
| | Bought Butane | | 15 | | 54.37 | | | |
January 2011 — December 2011 | | Sold WTI | | 7 | | 86.06 | | | |
| | Bought Butane | | 10 | | 59.64 | | | |
January 2011 — December 2011 | | Sold WTI | | 7 | | 83.01 | | | |
| | Bought Butane | | 10 | | 57.28 | | | |
January 2011 — December 2011 | | Bought WTI | | 7 | | 81.33 | | | |
| | Sold Butane | | 10 | | 57.70 | | | |
January 2011 — December 2011 | | Bought WTI | | 7 | | 81.55 | | | |
| | Sold Butane | | 10 | | 57.54 | | | |
January 2011 — December 2011 | | Bought WTI | | 7 | | 82.23 | | | |
| | Sold Butane | | 10 | | 58.59 | | | |
January 2011 — December 2011 | | Bought WTI | | 3 | | 80.09 | | | |
| | Sold Butane | | 5 | | 57.07 | | | |
January 2011 — December 2011 | | Sold WTI | | 7 | | 89.02 | | | |
| | Bought Butane | | 10 | | 63.47 | | | |
January 2011 — December 2011 | | Sold WTI | | 7 | | 85.94 | | | |
| | Bought Butane | | 10 | | 65.10 | | | |
January 2011 — December 2011 | | Bought WTI | | 7 | | 85.95 | | | |
| | Sold Butane | | 10 | | 61.58 | | | |
January 2011 — December 2011 | | Bought WTI | | 7 | | 83.34 | | | |
| | Sold Butane | | 10 | | 63.63 | | | |
| | | | | | | | $ | 392 | |
| | | | | | | | | | |
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. The Company has also entered into forward contracts to buy U.S. dollars to fix the exchange rate on a portion of the future interest payments on debt denominated in U.S. dollars.
USD Forwards
Term | | Contract | | Volume U.S.$ | | Weighted average
exchange rate
(CAD$/U.S.$) | | Fair value | |
| | | | | | | | | |
January 25, 2011 | | Forward sell | | 47,500,000 | | $ | 1.0074 | | | |
| | | | | | | | $ | 783 | |
January 14, 2011 | | Forward buy | | 7,500,000 | | 0.9999 | | | |
| | | | | | | | (68 | ) |
| | | | | | | | | | | |
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(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 | |
| | | | | | | | | |
January 1, 2011 — December 31, 2012 | | Bought Fixed Price | | 72 | | $ | 80.49 | | $ | (1,463 | ) |
| | | | | | | | | | | |
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:
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
Current | | | | | |
Accounts receivable | | $ | 1,812 | | $ | 752 | |
Accounts payable and accrued charges | | (3,252 | ) | (3,565 | ) |
| | $ | (1,440 | ) | $ | (2,813 | ) |
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Notes to Consolidated Financial Statements
(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 Credit facility, the Company is subject to interest rate risk as borrowings bear interest at a rate equal to, at the Company’s option, either LIBOR, the prime rate, the Bankers Acceptance rate or the Above Bank Rate, plus an applicable margin based on a pricing grid.
(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. In addition, the Company maintains accounts receivable insurance for customers with an approved credit limit from $200,000 to $10,000,000. Allowance for doubtful accounts was $2,157,000 and $386,000 at December 31, 2010 and December 31, 2009, respectively (note 3). At December 31, 2010, approximately
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
7.0% of trade receivables are past due but considered to be not impaired. The maximum exposure to credit risk related to accounts receivable is their carrying value, as disclosed in the financial statements.
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 or commodity brokers, with investment grade credit ratings as determined by recognized credit rating agencies.
The Company’s cash equivalents are placed in high-quality commercial paper, money market funds and time deposits with major international banks and financial institutions.
(e) Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. This risk relates to the Company’s ability to generate or obtain sufficient cash or cash equivalents to satisfy these financial obligations as they become due. The Company’s process for managing liquidity risk include preparing and monitoring capital and operating budgets, coordinating and authorizing project expenditures, and authorization of contractual agreements. The Company seeks additional financing based on the results of these processes. The budgets are updated with forecasts when required as conditions change. Sufficient funds and the Credit facility are available to satisfy both the Company’s long and short-term requirements. The Credit facility totals U.S.$200,000,000 and at December 31, 2010 there was $43,500,000 drawn against the facility. In addition, the Company has issued Letters of Credit totaling $59,242,000 as at December 31, 2010.
Set out below is maturity analyses of certain of the Company’s financial liabilities as recorded on the balance sheet at December 31, 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 | |
| | | | | | | | | |
Credit facility | | $ | 43,500 | | $ | — | | $ | — | | $ | 43,500 | |
Accounts payable and accrued charges | | 378,776 | | — | | — | | 378,776 | |
Long-term debt | | — | | 556,976 | | 198,920 | | 755,896 | |
Accrued interest on long-term debt | | 14,910 | | — | | — | | 14,910 | |
Total financial liabilities | | $ | 437,186 | | $ | 556,976 | | $ | 198,920 | | $ | 1,193,082 | |
(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
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
sensitivity analysis relates to the position as at December 31, 2010. The analysis excludes the impact of movements in market variables on the carrying value of pension and other post retirement obligations.
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.
| | Favorable 15% Change | | Unfavorable 15% Change | |
| | December 31,
2010 | | December 31,
2009 | | December 31,
2010 | | December 31,
2009 | |
Crude oil related contracts | | $ | 6,005 | | $ | 3,335 | | $ | (6,005 | ) | $ | (3,335 | ) |
| | | | | | | | | | | | | |
| | Favorable 10% Change | | Unfavorable 10% Change | |
| | December 31,
2010 | | December 31,
2009 | | December 31,
2010 | | December 31,
2009 | |
Electricity contracts | | $ | 187 | | $ | 292 | | $ | (187 | ) | $ | (292 | ) |
| | | | | | | | | | | | | |
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
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 | |
| | December 31,
2010 | | December 31,
2009 | | December 31,
2010 | | December 31,
2009 | |
| | | | | | | | | |
USD Forwards | | $ | 1,440 | | $ | 1,003 | | $ | (1,440 | ) | $ | (1,003 | ) |
Long-term debt | | 32,504 | | 25,056 | | (32,504 | ) | (25,056 | ) |
| | | | | | | | | | | | | |
Capital management
The Company’s objectives when managing its capital structure are to maintain financial flexibility so as to preserve the Company’s ability to meet its financial obligations and to finance internally generated growth as well as potential acquisitions.
The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include shareholders’ equity, long-term debt, the Credit facility and working capital. To maintain or adjust the
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
capital structure, the Company may raise debt or equity and/or adjust its capital spending to manage its current and projected debt levels.
The terms of the Credit facility require the Company to comply with financial covenants when the available amount under the facility is less than 15% of the facility, including maintaining a fixed charge coverage ratio. If the Company fails to comply with this covenant, the lenders may declare an event of default under the facility. At December 31, 2010, this covenant was not applicable as the amount available was not less than 15% of the facility.
At December 31, 2010, the Company did not meet the interest coverage ratio applicable under the terms of the First Lien Notes and Senior Notes. As a result, the Company is unable to incur certain additional indebtedness or to make certain acquisitions until the Company meets or exceeds the interest coverage ratio.
21 Net change in non-cash working capital
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Period from
December 13,
2008 to
December 31,
2008 | | Period from
January 1,
2008 to
December 12,
2008 | |
Decrease (increase) in current assets | | | | | | | | | |
Accounts receivable | | $ | (12,733 | ) | $ | (23,381 | ) | $ | 200,168 | | $ | (125,683 | ) |
Inventories | | (79,094 | ) | (41,570 | ) | 6,928 | | 31,279 | |
Income taxes receivable | | (41,757 | ) | (1,818 | ) | (4,872 | ) | (1,715 | ) |
Prepaid expenses | | (1,915 | ) | 3,917 | | (2,473 | ) | 1,484 | |
| | (135,499 | ) | (62,852 | ) | 199,751 | | (94,635 | ) |
Increase (decrease) in current liabilities | | | | | | | | | |
Accounts payable and accrued charges | | 100,671 | | (20,619 | ) | 170,285 | | 91,406 | |
Deferred revenue | | 41,296 | | 4,983 | | — | | (199 | ) |
Income taxes payable | | (7,226 | ) | 8,443 | | — | | — | |
| | 134,741 | | (7,193 | ) | 170,285 | | 91,207 | |
Net change in non-cash working capital related to operating activities | | $ | (758 | ) | $ | (70,045 | ) | $ | 29,466 | | $ | (3,428 | ) |
| | | | | | | | | |
Other disclosures: | | | | | | | | | |
Interest paid | | $ | 78,887 | | $ | 65,275 | | $ | — | | $ | 8,733 | |
Income taxes paid (note 22) | | 43,533 | | 1,877 | | (246 | ) | 38,094 | |
Non-cash contribution of foreign exchange contracts (note 16) | | — | | — | | (169,049 | ) | — | |
Settlement of the foreign exchange contracts by the Company’s parent (note 16) | | — | | — | | 169,049 | | — | |
Shares issued in connection with the Acquisition | | — | | — | | 100,000 | | — | |
Non-cash settlement of purchase price | | — | | — | | 157,000 | | — | |
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
22 Commitments and contingencies
Commitments
The Company is subject to certain commitments regarding future operating leases. There are operating lease commitments relating to railway tank cars, vehicles, computer hardware, field buildings and office space. These leases expire at various dates over the next 10 years. The minimum payments required under these commitments, net of sub-lease income, are as follows:
| | Total | |
| | | |
2011 | | $ | 18,300 | |
2012 | | 15,946 | |
2013 | | 12,256 | |
2014 | | 10,375 | |
2015 | | 10,214 | |
| | $ | 67,091 | |
Expenses related to operating leases were $21,675,000 for 2010, $15,753,000 for 2009, $683,000 and $12,455,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively.
Contingencies
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 described in Note 2, Hunting has indemnified the Company for the pre-closing period impact of these audits. Included in income tax receivable and accounts payable and accrued charges (note 11) as at December 31, 2010 is $53,568,000, 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.
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
23 Share Capital
| | Common Shares | | Preferred Shares | |
| | Shares | | Amount | | Shares | | Amount | |
Predecessor | | | | | | | | | |
| | | | | | | | | |
Balance as at December 31, 2007 | | 405,000 | | 405 | | — | | — | |
Balance as at December 12, 2008 | | 405,000 | | $ | 405 | | — | | $ | — | |
| | | | | | | | | |
Successor | | | | | | | | | |
Issuance of common shares in connection with the Acquisition | | 537,656 | | $ | 537,656 | | — | | $ | — | |
Issuance of preferred shares in connection with the Acquisition | | — | | — | | 100,000 | | 100,000 | |
Dividends on preferred shares | | — | | — | | — | | 625 | |
Balance as at December 31, 2008 | | 537,656 | | 537,656 | | 100,000 | | 100,625 | |
Dividends on preferred shares | | — | | — | | — | | 12,409 | |
Balance as at December 31, 2009 | | 537,656 | | 537,656 | | 100,000 | | 113,034 | |
Dividends on preferred shares | | — | | — | | — | | 14,034 | |
Balance as at December 31, 2010 | | 537,656 | | $ | 537,656 | | 100,000 | | $ | 127,068 | |
Common shares
The authorized common shares of the Company consist of an unlimited number of Class A and Class B Common shares.
The Class A common shares shall entitle the holder to one vote per share; entitle the holder to such dividends as the Board of Directors may from time to time declare; in the event of a liquidation event or sale transaction and subject to the conditions of the Class B common shares and Preferred Shares, entitle the holder to the surplus assets of the Company.
The Class B common shares shall entitle the holder to one vote per share; entitle the holder to such dividends as the Board of Directors may from time to time declare; in the event of a liquidation event or sale transaction and before any payment or distribution is made to any other classes, entitle the holder to an amount equal to the greater of (i) the aggregate accreted value of the preferred shares that were converted into Class B common shares or (ii) the product of the number of Class B shares outstanding at that time and the Class A common share amount; in the event of a public offering of common shares resulting in net proceeds of U.S.$100,000,000, entitle the holder of each share to automatically convert into Class A common shares equal to the greater of (i) one or (ii) the accreted value of the preferred shares converted into Class B common shares on the conversion date divided by the offering price for the common shares.
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Preferred shares
The authorized preferred shares of the Company consist of 100,000 preferred shares. The key terms of the preferred shares, which were amended on December 9, 2010, are as follows:
Rank. The preferred shares shall, for all purposes, rank senior to the existing common shares and to common shares created in the future.
Voting rights. The holders of the preferred shares have no voting rights.
Dividends. The holders of the preferred shares are entitled to receive a mandatory cumulative dividend at an annual rate of 12% of the accreted value for each preferred share until December 12, 2010. From December 13, 2010 to September 1, 2011 the annual rate increases to 13% of the accreted value for each preferred share. Unless otherwise determined by the Board of Directors, the accrued dividends shall not be paid in cash but instead shall compound and be added to the accreted value of the preferred shares on a semi-annual basis. The Company is not permitted to declare or pay any dividends to the holder of common shares as long as the preferred shares are outstanding.
Redemption. At any time prior to September 1, 2011, the Company can elect to redeem the preferred shares for a cash payment equal to the issue price per share, plus all unpaid dividends that have accrued. If the preferred shares are not redeemed by the Company by September 1, 2011, $10,000,000 will be added to the accreted value at that date.
Conversion. The preferred shares are automatically convertible into Class B common shares if the preferred shares are outstanding at September 1, 2011. Each preferred share shall be convertible into such number of Class B common shares as is determined by dividing the accreted value of the preferred shares plus all accrued dividends at September 1, 2011 by $1,000.
Liquidation preference. In the event of a liquidation event or sale transaction, each preferred share holder shall be entitled to receive for each of its preferred shares, out of any lawfully available assets of the Company, in preference to the holders of common shares and any other preferred shares, an amount equal to the face amount plus any accrued and unpaid dividends due on such preferred shares.
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
24 Segmental 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 fractionation 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 financial statements.
F-53
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Successor | |
Year Ended
December 31, 2010 | | Marketing | | Truck
Transportation | | Terminals &
Pipelines | | Propane &
NGL
Marketing &
Distribution | | Processing &
Wellsite Fluids | | Corporate
& other
reconciling
balances | | Total | |
Statement of income (loss) | | | | | | | | | | | | | | | |
Revenue - external and inter-segmental | | $ | 2,928,133 | | $ | 351,568 | | $ | 903,100 | | $ | 759,134 | | $ | 418,897 | | $ | — | | $ | 5,360,832 | |
Revenue - inter-segmental | | (538,230 | ) | (49,201 | ) | (857,668 | ) | (124,787 | ) | (112,958 | ) | — | | (1,682,844 | ) |
Revenue - external | | 2,389,903 | | 302,367 | | 45,432 | | 634,347 | | 305,939 | | — | | 3,677,988 | |
| | | | | | | | | | | | | | | |
Cost of product & service — external & inter-segmental | | 2,908,153 | | 239,155 | | 838,574 | | 685,366 | | 365,995 | | — | | 5,037,243 | |
Operating and other costs | | 11,856 | | 59,102 | | 23,283 | | 38,900 | | 19,019 | | — | | 152,160 | |
Cost of product & service — inter-segmental | | (538,230 | ) | (49,201 | ) | (857,668 | ) | (124,787 | ) | (112,958 | ) | — | | (1,682,844 | ) |
Cost of sales-external | | 2,381,779 | | 249,056 | | 4,189 | | 599,479 | | 272,056 | | — | | 3,506,559 | |
| | | | | | | | | | | | | | | |
| | 8,124 | | 53,311 | | 41,243 | | 34,868 | | 33,883 | | — | | 171,429 | |
| | | | | | | | | | | | | | | |
Foreign exchange loss (gain) | | 94 | | (2 | ) | — | | 342 | | (259 | ) | — | | 175 | |
Gain on sale of assets | | — | | — | | (2 | ) | (34 | ) | (1 | ) | — | | (37 | ) |
Loss from equity investments | | — | | — | | 697 | | 217 | | — | | — | | 914 | |
Segmental operating profit | | 8,030 | | 53,313 | | 40,548 | | 34,343 | | 34,143 | | — | | 170,377 | |
| | | | | | | | | | | | | | | |
Depreciation of property, plant and equipment | | 2,026 | | 22,117 | | 24,955 | | 7,095 | | 6,010 | | 2,765 | | 64,968 | |
Amortization of intangible assets | | 677 | | 11,332 | | 2,431 | | 5,468 | | 9,269 | | — | | 29,177 | |
General and administrative | | — | | — | | — | | — | | — | | 24,935 | | 24,935 | |
Stock based compensation | | — | | — | | — | | — | | — | | 4,629 | | 4,629 | |
Accretion expense | | — | | — | | — | | — | | — | | 787 | | 787 | |
Foreign exchange gain | | — | | — | | — | | — | | — | | (40,055 | ) | (40,055 | ) |
Interest expense | | — | | — | | — | | — | | — | | 99,451 | | 99,451 | |
Interest income | | — | | — | | — | | — | | — | | (324 | ) | (324 | ) |
Income tax recovery | | — | | — | | — | | — | | — | | (13,346 | ) | (13,346 | ) |
Net income | | $ | 5,327 | | $ | 19,864 | | $ | 13,162 | | $ | 21,780 | | $ | 18,864 | | $ | (78,842 | ) | $ | 155 | |
| | | | | | | | | | | | | | | |
Non-current assets | | | | | | | | | | | | | | | |
Property, plant and equipment | | $ | 766 | | $ | 143,609 | | $ | 317,349 | | $ | 80,137 | | $ | 90,616 | | $ | 20,408 | | $ | 652,885 | |
Goodwill | | 43,555 | | 45,810 | | 199,867 | | 91,921 | | 117,664 | | — | | 498,817 | |
Intangible assets | | 3,617 | | 72,139 | | 17,955 | | 31,149 | | 29,750 | | — | | 154,610 | |
Other segmental items | | | | | | | | | | | | | | | |
Capital expenditures: | | | | | | | | | | | | | | | |
Property, plant and equipment | | 111 | | 18,894 | | 15,817 | | 8,954 | | 9,464 | | 8,442 | | 61,682 | |
Intangible assets | | — | | 44,816 | | 1,512 | | 12,293 | | — | | — | | 58,621 | |
Goodwill | | — | | 42,155 | | 1,587 | | 23,507 | | — | | — | | 67,249 | |
Total assets | | 342,874 | | 322,005 | | 581,920 | | 348,851 | | 315,049 | | 112,066 | | 2,022,765 | |
F-54
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Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Successor | |
Year Ended
December 31, 2009 | | Marketing | | Truck
Transportation | | Terminals &
Pipelines | | Propane &
NGL
Marketing &
Distribution | | Processing &
Wellsite Fluids | | Corporate
& other
reconciling
balances | | Total | |
Statement of income (loss) | | | | | | | | | | | | | | | |
Revenue - external and inter-segmental | | $ | 2,989,881 | | $ | 229,258 | | $ | 597,500 | | $ | 492,360 | | $ | 335,394 | | $ | — | | $ | 4,644,393 | |
Revenue - inter-segmental | | (414,591 | ) | (43,788 | ) | (549,139 | ) | (71,233 | ) | (111,505 | ) | — | | (1,190,256 | ) |
Revenue - external | | 2,575,290 | | 185,470 | | 48,361 | | 421,127 | | 223,889 | | — | | 3,454,137 | |
| | | | | | | | | | | | | | | |
Cost of product & service — external & inter-segmental | | 2,964,879 | | 151,555 | | 526,150 | | 416,053 | | 291,712 | | — | | 4,350,349 | |
Operating and other costs | | 10,946 | | 44,980 | | 24,316 | | 36,266 | | 15,820 | | — | | 132,328 | |
Cost of product & service — inter-segmental | | (414,591 | ) | (43,788 | ) | (549,139 | ) | (71,233 | ) | (111,505 | ) | — | | (1,190,256 | ) |
Cost of sales-external | | 2,561,234 | | 152,747 | | 1,327 | | 381,086 | | 196,027 | | — | | 3,292,421 | |
| | | | | | | | | | | | | | | |
| | 14,056 | | 32,723 | | 47,034 | | 40,041 | | 27,862 | | — | | 161,716 | |
| | | | | | | | | | | | | | | |
Foreign exchange loss (gain) | | 941 | | 4 | | (1 | ) | 1,330 | | (1,134 | ) | — | | 1,140 | |
Gain on sale of assets | | — | | (78 | ) | — | | (12 | ) | — | | — | | (90 | ) |
Loss (income) from equity investments | | — | | — | | 111 | | (57 | ) | — | | — | | 54 | |
Segmental operating profit | | 13,115 | | 32,797 | | 46,924 | | 38,780 | | 28,996 | | — | | 160,612 | |
| | | | | | | | | | | | | | | |
Depreciation of property, plant and equipment | | 1,984 | | 17,318 | | 23,446 | | 5,542 | | 5,638 | | 2,636 | | 56,564 | |
Amortization of intangible assets | | 671 | | 9,772 | | 2,258 | | 3,652 | | 9,394 | | — | | 25,747 | |
General and administrative | | — | | — | | — | | — | | — | | 24,731 | | 24,731 | |
Stock based compensation | | — | | — | | — | | — | | — | | 8,957 | | 8,957 | |
Impairment of goodwill and intangible assets | | — | | 114,115 | | — | | — | | — | | — | | 114,115 | |
Accretion expense | | — | | — | | — | | — | | — | | 785 | | 785 | |
Foreign exchange gain | | — | | — | | — | | — | | — | | (93,821 | ) | (93,821 | ) |
Debt extinguishment costs | | — | | — | | — | | — | | — | | 18,517 | | 18,517 | |
Interest expense | | — | | — | | — | | — | | — | | 80,868 | | 80,868 | |
Interest income | | — | | — | | — | | — | | — | | (253 | ) | (253 | ) |
Income tax recovery | | — | | — | | — | | — | | — | | (12,649 | ) | (12,649 | ) |
Net income (loss) | | $ | 10,460 | | $ | (108,408 | ) | $ | 21,220 | | $ | 29,586 | | $ | 13,964 | | $ | (29,771 | ) | $ | (62,949 | ) |
| | | | | | | | | | | | | | | |
Non-current assets | | | | | | | | | | | | | | | |
Property, plant and equipment | | $ | 35,192 | | $ | 110,275 | | $ | 274,009 | | $ | 77,524 | | $ | 87,028 | | $ | 14,798 | | $ | 598,826 | |
Goodwill | | 43,555 | | 5,020 | | 198,343 | | 69,312 | | 117,664 | | — | | 433,894 | |
Intangible assets | | 4,295 | | 39,950 | | 18,925 | | 24,766 | | 39,019 | | — | | 126,955 | |
Other segmental items | | | | | | | | | | | | | | | |
Capital expenditures: | | | | | | | | | | | | | | | |
Property, plant and equipment | | 612 | | 10,276 | | 7,046 | | 8,983 | | 7,995 | | 2,055 | | 36,967 | |
Intangible assets | | — | | 1,950 | | — | | 1,020 | | — | | — | | 2,970 | |
Goodwill | | — | | 707 | | — | | 525 | | — | | — | | 1,232 | |
Total assets | | 312,708 | | 190,345 | | 510,225 | | 265,645 | | 304,665 | | 90,306 | | 1,673,894 | |
F-55
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Successor | |
Period from December 13, 2008
to December 31, 2008 | | 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 | | $ | 86,876 | | $ | 14,582 | | $ | 18,488 | | $ | 34,693 | | $ | 16,464 | | $ | — | | $ | 171,103 | |
Revenue - inter-segmental | | (9,350 | ) | (1,992 | ) | (14,104 | ) | (5,409 | ) | (4,777 | ) | — | | (35,632 | ) |
Revenue - external | | 77,526 | | 12,590 | | 4,384 | | 29,284 | | 11,687 | | — | | 135,471 | |
| | | | | | | | | | | | | | | |
Cost of product & service — external & inter-segmental | | 89,549 | | 9,672 | | 16,032 | | 27,873 | | 12,918 | | — | | 156,044 | |
Operating and other costs | | — | | 2,525 | | (17 | ) | 1,527 | | 525 | | — | | 4,560 | |
Cost of product & service — inter-segmental | | (9,350 | ) | (1,992 | ) | (14,104 | ) | (5,409 | ) | (4,777 | ) | — | | (35,632 | ) |
Cost of sales-external | | 80,199 | | 10,205 | | 1,911 | | 23,991 | | 8,666 | | — | | 124,972 | |
| | | | | | | | | | | | | | | |
| | (2,673 | ) | 2,385 | | 2,473 | | 5,293 | | 3,021 | | — | | 10,499 | |
| | | | | | | | | | | | | | | |
Foreign exchange (gain) loss | | (565 | ) | — | | — | | 212 | | 262 | | — | | (91 | ) |
Loss on sale of assets | | — | | — | | — | | 18 | | — | | — | | 18 | |
Loss from equity investments | | — | | — | | 10 | | 11 | | — | | — | | 21 | |
Segmental operating profit (loss) | | (2,108 | ) | 2,385 | | 2,463 | | 5,052 | | 2,759 | | — | | 10,551 | |
| | | | | | | | | | | | | | | |
Depreciation of property, plant and equipment | | 182 | | 939 | | 1,708 | | 271 | | 303 | | 155 | | 3,558 | |
Amortization of intangible assets | | 34 | | 483 | | 117 | | 178 | | 511 | | — | | 1,323 | |
General and administrative | | — | | — | | — | | — | | — | | 615 | | 615 | |
Accretion expense | | — | | — | | — | | — | | — | | 22 | | 22 | |
Foreign exchange gain | | — | | — | | — | | — | | — | | (4,396 | ) | (4,396 | ) |
Interest expense | | — | | — | | — | | — | | — | | 3,431 | | 3,431 | |
Interest income | | — | | — | | — | | — | | — | | (12 | ) | (12 | ) |
Income tax expense | | — | | — | | — | | — | | — | | 1,030 | | 1,030 | |
Net income (loss) | | $ | (2,324 | ) | $ | 963 | | $ | 638 | | $ | 4,603 | | $ | 1,945 | | $ | (845 | ) | $ | 4,980 | |
| | | | | | | | | | | | | | | |
Non-current assets | | | | | | | | | | | | | | | |
Property, plant and equipment | | $ | 35,883 | | $ | 114,464 | | $ | 298,289 | | $ | 66,782 | | $ | 82,375 | | $ | 15,187 | | $ | 603,980 | |
Goodwill | | 68,155 | | 89,783 | | 198,343 | | 44,187 | | 117,664 | | — | | 518,132 | |
Intangible assets | | 4,966 | | 76,440 | | 21,183 | | 27,399 | | 48,389 | | — | | 178,377 | |
Other segmental items | | | | | | | | | | | | | | | |
Capital expenditures: | | | | | | | | | | | | | | | |
Property, plant and equipment | | 114 | | 220 | | 813 | | 514 | | 1,235 | | 87 | | 2,983 | |
Total assets | | 247,883 | | 342,446 | | 507,477 | | 280,763 | | 292,743 | | 178,388 | | 1,849,700 | |
F-56
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Predecessor | |
Period from January 1, 2008
to December 12, 2008 | | 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 | | $ | 3,889,232 | | $ | 286,797 | | $ | 871,505 | | $ | 667,687 | | $ | 523,943 | | $ | — | | $ | 6,239,164 | |
Revenue - inter-segmental | | (434,004 | ) | (34,248 | ) | (739,366 | ) | (207,885 | ) | (174,996 | ) | — | | (1,590,499 | ) |
Revenue - external | | 3,455,228 | | 252,549 | | 132,139 | | 459,802 | | 348,947 | | — | | 4,648,665 | |
| | | | | | | | | | | | | | | |
Cost of product & service — external & inter-segmental | | 3,864,691 | | 181,254 | | 809,226 | | 606,453 | | 466,756 | | — | | 5,928,380 | |
Operating and other costs | | 11,829 | | 59,306 | | 19,738 | | 34,894 | | 27,491 | | — | | 153,258 | |
Cost of product & service — inter-segmental | | (434,004 | ) | (34,248 | ) | (739,366 | ) | (207,885 | ) | (174,996 | ) | — | | (1,590,499 | ) |
Cost of sales-external | | 3,442,516 | | 206,312 | | 89,598 | | 433,462 | | 319,251 | | — | | 4,491,139 | |
| | | | | | | | | | | | | | | |
| | 12,712 | | 46,237 | | 42,541 | | 26,340 | | 29,696 | | — | | 157,526 | |
| | | | | | | | | | | | | | | |
Foreign exchange (gain) loss | | (3,025 | ) | 2 | | (2 | ) | (910 | ) | 3,402 | | — | | (533 | ) |
Loss (gain) on sale of assets | | 77 | | (82 | ) | (42 | ) | (63 | ) | 2 | | — | | (108 | ) |
Loss from equity investments | | — | | — | | 134 | | 202 | | — | | — | | 336 | |
Segmental operating profit | | 15,660 | | 46,317 | | 42,451 | | 27,111 | | 26,292 | | — | | 157,831 | |
| | | | | | | | | | | | | | | |
Depreciation of property, plant and equipment | | 1,191 | | 8,302 | | 7,678 | | 4,749 | | 3,666 | | 2,811 | | 28,397 | |
Amortization of intangible assets | | — | | 652 | | — | | 1,718 | | 739 | | — | | 3,109 | |
General and administrative | | — | | — | | — | | — | | — | | 31,365 | | 31,365 | |
Accretion expense | | — | | — | | — | | — | | — | | 404 | | 404 | |
Foreign exchange loss | | — | | — | | — | | — | | — | | 50 | | 50 | |
Interest expense | | — | | — | | — | | — | | — | | 8,335 | | 8,335 | |
Interest income | | — | | — | | — | | — | | — | | (346 | ) | (346 | ) |
Income tax expense | | — | | — | | — | | — | | — | | 25,199 | | 25,199 | |
Net income | | $ | 14,469 | | $ | 37,363 | | $ | 34,773 | | $ | 20,644 | | $ | 21,887 | | $ | (67,818 | ) | $ | 61,318 | |
| | | | | | | | | | | | | | | |
Other segmental items | | | | | | | | | | | | | | | |
Capital expenditures: | | | | | | | | | | | | | | | |
Property, plant and equipment | | $ | 5,776 | | $ | 12,018 | | $ | 8,856 | | $ | 6,555 | | $ | 10,929 | | $ | 2,214 | | $ | 46,348 | |
Intangible assets | | — | | 3,350 | | — | | — | | — | | — | | 3,350 | |
Goodwill | | — | | 4,733 | | — | | — | | — | | — | | 4,733 | |
Investment in equity investments | | — | | — | | 3,750 | | — | | — | | — | | 3,750 | |
F-57
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
Geographic Data
Based on the location of the end user, approximately 20% and 11% of revenue was to customers in the United States for the year ended December 31, 2010 and 2009, respectively. For the period from December 13, 2008 to December 31, 2008, the period from January 1, 2008 to December 12, 2008, the Company did not have any material revenues outside of Canada.
The Company’s long lived assets are primarily concentrated in Canada with 11% in the United States at December 31, 2010. The Company did not have any material long lived assets outside of Canada at December 31, 2009.
F-58
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
25 United 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):
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | From
December 13,
2008 to
December 31,
2008 | | From
January 1,
2008 to
December 12,
2008 | |
| | | | | | | | | |
Net income (loss) - Canadian GAAP | | $ | 155 | | $ | (62,949 | ) | $ | 4,980 | | $ | 61,318 | |
Capitalized interest (a) | | 1,206 | | 282 | | — | | 245 | |
Stock based compensation (b) | | — | | — | | — | | (126 | ) |
Business combinations (c) | | (2,746 | ) | (155 | ) | — | | — | |
Tax impact of the above adjustments | | 432 | | (37 | ) | — | | (79 | ) |
Net income (loss) — U.S. GAAP | | (953 | ) | (62,859 | ) | 4,980 | | 61,358 | |
| | | | | | | | | |
Other comprehensive income | | | | | | | | | |
Pensions and post-retirement benefits, net of tax (d) | | (346 | ) | (1,429 | ) | — | | (1,055 | ) |
Comprehensive income (loss) — U.S. GAAP | | (1,299 | ) | (64,288 | ) | 4,980 | | 60,303 | |
| | | | | | | | | |
Shareholder’s equity | | | | | | | | | |
Opening balance — U.S. GAAP | | 474,271 | | 542,011 | | — | | 258,195 | |
Share capital issued in connection with the Acquisition | | — | | — | | 537,656 | | — | |
Net income (loss) — U.S. GAAP | | (953 | ) | (62,859 | ) | 4,980 | | 61,358 | |
Pensions and post-retirement benefits (d) | | (346 | ) | (1,429 | ) | — | | (1,055 | ) |
Stock based compensation (b) | | 4,629 | | 8,957 | | — | | 126 | |
Dividends on preferred shares (e) | | (14,034 | ) | (12,409 | ) | (625 | ) | — | |
Foreign currency translation adjustment | | (6,767 | ) | — | | — | | — | |
Closing balance — U.S. GAAP | | 456,800 | | 474,271 | | 542,011 | | 318,624 | |
| | | | | | | | | |
Accumulated other comprehensive loss | | | | | | | | | |
Opening balance — U.S. GAAP | | (1,429 | ) | — | | — | | (2,210 | ) |
Pension and post-retirement benefits (d) | | (346 | ) | (1,429 | ) | — | | (1,055 | ) |
Closing balance — U.S. GAAP | | $ | (1,775 | ) | $ | (1,429 | ) | $ | — | | $ | (3,265 | ) |
F-59
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Successor | |
| | December 31,
2010 | | December 31,
2009 | |
Shareholder’s Equity | | | | | |
Shareholder’s equity — Canadian GAAP (1) | | $ | 586,661 | | $ | 588,644 | |
Increase (decrease) in shareholders equity under U.S. GAAP | | | | | |
Capitalized interest (a) | | 1,488 | | 282 | |
Business combinations (c) | | (2,901 | ) | (155 | ) |
Pension and post-retirement benefits (d) | | (2,494 | ) | (2,013 | ) |
Tax impact of the above changes | | 1,114 | | 547 | |
Reclassification of preferred shares as temporary equity (mezzanine) (e) | | (127,068 | ) | (113,034 | ) |
Shareholder’s equity — U.S. GAAP | | $ | 456,800 | | $ | 474,271 | |
(1) Riverstone capitalized the Company with cash of $537,656,000 in exchange for 537,656 common shares. As part of the capitalization, Riverstone contributed to the Company certain foreign exchange contracts with a negative value of $169,049,000. Subsequent to contributing the contracts, Riverstone settled the contracts and paid the amount due to the counterparties on behalf of the Company.
[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 $1,206,000 and $282,000 for 2010 and 2009, net of amortization of $53,000 and $63,000, and $0 and $245,000 for the period from December 13, 2008 to December 31, 2008 and the period from January 1, 2008 to December 12, 2008, respectively, net of amortization of $0, and $40,000, respectively. Total accumulated interest costs capitalized as at December 31, 2010 and 2009 was $1,488,000 and $282,000, respectively, net of accumulated amortization of $116,000 and $63,000, respectively. As a result of the purchase method of accounting and the allocation of the purchase price to the net tangible and intangible assets acquired based on their estimated fair values in connection with the Acquisition, there was no difference in the total accumulated interest costs under Canadian GAAP and U.S. GAAP as at December 31, 2008.
[b] Stock-based compensation
In accordance with the Hunting Unapproved Share Option Plan, vesting in certain of the awards was contingent on the attainment of performance and service conditions and also on earnings targets indexed to inflation rates. Under Canadian GAAP, these dual-indexed awards are classified as equity awards. Under U.S. GAAP, an award which is indexed to a factor that is not a market, performance or service condition is required to be classified as a liability until the feature that is not a performance or service condition is resolved, at which point the award will be classified as equity awards. Liability treatment of these awards requires the Company to measure the fair value of the unvested portion of the award at the end of each reporting period and recognize the related compensation expense. As a result, additional compensation expense of $126,000 for the period from January 1, 2008 to December 12, 2008, is recorded under U.S. GAAP. The additional compensation expense has been credited to equity as a contribution from Hunting since the Company is not required to reimburse Hunting for the incremental U.S. GAAP compensation
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
expense. Following the Acquisition, these dual indexed awards no longer existed and no additional expense is recorded for 2010, 2009 and the period from December 13, 2008 to December 31, 2008 under U.S. GAAP.
[c] 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 year ended December 31, 2010 and 2009, the Company incurred $2,746,000 and $155,000 of direct costs of a business combination that were capitalized under Canadian GAAP that would not be capitalized under U.S. GAAP. As of December 31, 2010, the total accumulated adjustment to U.S. GAAP retained earnings was $2,901,000.
[d] 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 a result, pension and other post-retirement liabilities decreased in 2010 by $481,000, net of tax of $135,000, decreased by $2,013,000, net of tax of $584,000 for 2009, and increased by $1,055,000, net of tax of $453,000 for the period January 1, 2008 to December 12, 2008. During the period from December 12, 2008 to December 31, 2008, there was no difference in the Company’s comprehensive income between Canadian GAAP and U.S. GAAP. As at December 31, 2010, the total cumulative adjustments to liabilities and accumulated other comprehensive income was $1,775,000.
[e] 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.
[f] Consolidated Statement of Cash flow
There are no material differences between the Consolidated Statement of Cash Flows under U.S. GAAP and Canadian GAAP.
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
[g] 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:
Unaudited pro forma financial information
U.S. GAAP requires supplemental unaudited pro forma statement of income information for the period in which a material business combination occurs. Material business combinations must be presented as if the acquisition had taken place at the beginning of the fiscal period.
The following unaudited pro forma financial information combines the Company’s consolidated results with the results of the acquired companies in the year ended December 31, 2010, as if the combinations had occurred at the beginning of the periods presented. In addition, it also assumes the issuance of the Senior Notes at the beginning of the periods presented.
| | Successor | |
| | Year ended
December 31,
2010
(unaudited) | | Year ended
December 31,
2009
(unaudited) | |
| | | | | |
Revenue | | $ | 3,816,131 | | $ | 3,809,893 | |
Loss before income taxes | | (14,779 | ) | (94,914 | ) |
Net loss | | $ | (723 | ) | $ | (76,332 | ) |
The pro forma information includes the impact of depreciation and amortization on the new carrying value of property, plant and equipment and intangible assets and interest expense on the Senior Notes.
The business combinations that occurred in the year ended December 31, 2009 as disclosed in Note 9 were not considered material for purposes of preparing unaudited pro forma financial information.
The following unaudited pro forma financial information for the year ended December 31, 2008 represents the combined U.S. GAAP historical audited results of Predecessor Company for the period from January 1, 2008 to December 12, 2008 and the historical audited results of Successor Company for the period from December 13, 2008 to December 31, 2008, adjusted on a pro forma basis to give effect to the issuance of debt and the Acquisition of Predecessor Company, as if the Acquisition had occurred at the beginning of the period presented.
| | Year ended
December 31,
2008
(unaudited) | |
| | | |
Revenue | | $ | 4,784,136 | |
Loss before income taxes | | (28,361 | ) |
Net loss | | $ | (18,972 | ) |
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
The pro forma information includes the impact of depreciation and amortization on the new carrying value of property, plant and equipment and intangible assets, interest expense on the long-term debt and expense related to the management agreements.
The pro forma information is not necessarily indicative of the results of operations that would have occurred had the Acquisition taken place on the date indicated, nor are they necessarily indicative of future results of operations.
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 $37,742,000 from long-term debt to long-term prepaid expenses and other assets on the balance sheet as at December 31, 2010.
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.
| | Successor | | Predecessor | |
| | Year ended
December 31,
2010 | | Year ended
December 31,
2009 | | Period from
December 13,
2008 to
December 31,
2008 | | Period from
January 1,
2008 to
December 12,
2008 | |
Revenues | | | | | | | | | |
Realized gains | | $ | 232 | | $ | 48,349 | | $ | 8,126 | | $ | 50,080 | |
Unrealized gains | | 1,062 | | 779 | | 112 | | 46,261 | |
Realized losses | | (1,874 | ) | (3,148 | ) | — | | (26,170 | ) |
Unrealized losses | | (11,884 | ) | (46,080 | ) | (346 | ) | (253 | ) |
| | (12,464 | ) | (100 | ) | 7,892 | | 69,918 | |
| | | | | | | | | |
Cost of sales | | | | | | | | | |
Realized gains | | 15,893 | | 29,922 | | 7,698 | | 54,434 | |
Unrealized gains | | 15,947 | | 50,059 | | 813 | | 12,740 | |
Realized losses | | (15,995 | ) | (77,947 | ) | (10,724 | ) | (78,588 | ) |
Unrealized losses | | (3,684 | ) | (14,450 | ) | (2,036 | ) | (50,401 | ) |
| | 12,161 | | (12,416 | ) | (4,249 | ) | (61,815 | ) |
| | | | | | | | | |
Interest expense | | | | | | | | | |
Unrealized losses | | (68 | ) | — | | — | | — | |
Total net effect | | $ | (371 | ) | $ | (12,516 | ) | $ | 3,643 | | $ | 8,103 | |
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
[i] New Accounting Pronouncements – U.S. GAAP
In December 2007, the FASB issued guidance that establishes principles and requirements for how an acquirer: (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree; (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The guidance is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The Company adopted the guidance on January 1, 2009.
In December 2007, the FASB issued guidance that requires all entities to report non-controlling (minority) interests in subsidiaries as equity in the consolidated financial statements. The guidance eliminates the diversity that currently exists in accounting for transactions between an entity and non-controlling interests by requiring that they be treated as equity transactions. The provisions of the guidance are effective on a prospective basis for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008, except for presentation and disclosure requirements, which are to be applied retrospectively for all periods presented. The Company adopted the guidance on January 1, 2009 and the adoption did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.
In March 2008, the FASB issued guidance that is intended to provide users of financial statements with an enhanced understanding of: 1) How and why an entity uses derivative instruments; 2) How derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and 3) How derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008, with early application encouraged. The Company adopted the guidance on January 1, 2009, and as the guidance requires only additional disclosures concerning derivatives and hedging activities, the adoption did not impact the Company’s consolidated financial position, results of operations or cash flows.
In December, 2008, the FASB issued guidance on an employer’s disclosures about plan assets of a defined benefit pension or other post retirement plan. This guidance is effective for financial statements issued for fiscal years beginning after December 15, 2009. The Company adopted this guidance for the year ended December 31, 2009 and it did not have an impact on the Company’s consolidated financial position, results of operations or cash flows.
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.
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
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. Earlier application is prohibited. 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. The Company adopted the guidance on January 1, 2010. The adoption did not have any material impact on the Company’s consolidated financial position, results of operations, or cash flows. The Company will adopt the guidance that will be effective for annual periods beginning after December 15, 2010 on January 1, 2011. The Company does not expect that adoption of this guidance will have any material impact on the consolidated financial position, results of operations or cash flows.
26 Guarantor schedules
Gibson Energy Holding ULC is the parent of Gibson Energy ULC. Gibson Energy ULC, together with its direct subsidiary GEP Midstream Finance Corp., issued the outstanding Notes. The Notes are guaranteed by Gibson Energy Holding ULC. These guarantees are full, unconditional, joint and several. The following condensed consolidated financial statements are presented for the information of the holders of the Notes in accordance with Rule 3-10 of Regulation S-X and present the results of operations, financial position and cash flows of (i) Gibson Energy Holding ULC, which is the guarantor of the Notes; (ii) the Issuers, namely Gibson Energy ULC and GEP Midstream Finance Corp.; (iii) other guarantors, who are all the direct and indirect subsidiaries of Gibson Energy ULC and (iv) the eliminations necessary to arrive at the information of the Company on a consolidated basis. Investments in subsidiaries are presented under the equity method of accounting. The results of operations and cashflows for the period from January 1, 2008 to December 12, 2008 are not presented as the Company and the Issuers were not part of the consolidated group until the date of the Acquisition. The condensed consolidated financial statements have been prepared in accordance with Canadian GAAP as the differences to U.S. GAAP are not considered material. See Note 25 for the impact of the application of U.S. GAAP on the consolidated results.
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Balance Sheet
Successor | |
| | December 31, 2010 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
| | | | | | | | | | | |
Assets | | | | | | | | | | | |
Current assets | | | | | | | | | | | |
Cash and cash equivalents | | $ | — | | $ | 4,193 | | $ | 3,032 | | $ | — | | $ | 7,225 | |
Accounts receivable | | — | | 169,590 | | 516,478 | | (331,386 | ) | 354,682 | |
Income taxes receivable | | — | | 52,320 | | 4,810 | | — | | 57,130 | |
Inventories | | — | | — | | 197,483 | | — | | 197,483 | |
Prepaid expenses | | — | | 6,391 | | 2,358 | | — | | 8,749 | |
Net investment in capital leases | | — | | — | | 236 | | — | | 236 | |
Assets held for sale | | — | | — | | 32,985 | | — | | 32,985 | |
Total current assets | | — | | 232,494 | | 757,382 | | (331,386 | ) | 658,490 | |
Future income taxes | | — | | 7,149 | | 6,273 | | — | | 13,422 | |
Long-term prepaid expenses and other assets | | — | | 13,881 | | 10,395 | | — | | 24,276 | |
Net investment in capital leases | | — | | — | | 20,265 | | — | | 20,265 | |
Property, plant and equipment | | — | | 21,803 | | 631,082 | | — | | 652,885 | |
Investment in subsidiaries | | 586,661 | | 1,329,106 | | — | | (1,915,767 | ) | — | |
Intangible assets | | — | | — | | 154,610 | | — | | 154,610 | |
Goodwill | | — | | 35,727 | | 463,090 | | — | | 498,817 | |
Total assets | | $ | 586,661 | | $ | 1,640,160 | | $ | 2,043,097 | | $ | (2,247,153 | ) | $ | 2,022,765 | |
| | | | | | | | | | | |
Liabilities | | | | | | | | | | | |
Current liabilities | | | | | | | | | | | |
Credit facility | | $ | — | | $ | 43,500 | | $ | — | | $ | — | | $ | 43,500 | |
Accounts payable and accrued charges | | — | | 276,114 | | 448,958 | | (331,386 | ) | 393,686 | |
Deferred revenue | | — | | — | | 54,701 | | — | | 54,701 | |
Income taxes payable | | — | | 87 | | 1,130 | | — | | 1,217 | |
Current portion of future income taxes | | — | | 177 | | — | | — | | 177 | |
Liabilities related to assets held for sale | | — | | — | | 2,960 | | — | | 2,960 | |
Total current liabilities | | — | | 319,878 | | 507,749 | | (331,386 | ) | 496,241 | |
Asset retirement obligation | | — | | — | | 9,614 | | — | | 9,614 | |
Long-term debt | | — | | 718,154 | | — | | — | | 718,154 | |
Other long-term liabilities | | — | | 1,474 | | 14,181 | | — | | 15,655 | |
Future income taxes | | — | | 189,526 | | 6,914 | | — | | 196,440 | |
Shareholder’s equity | | 586,661 | | 411,128 | | 1,504,639 | | (1,915,767 | ) | 586,661 | |
Total liabilities and shareholder’s equity | | $ | 586,661 | | $ | 1,640,160 | | $ | 2,043,097 | | $ | (2,247,153 | ) | $ | 2,022,765 | |
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Statement of Income
Successor | |
| | Year ended December 31, 2010 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
| | | | | | | | | | | |
Revenue | | $ | — | | $ | 4,719 | | $ | 3,675,073 | | $ | (1,804 | ) | $ | 3,677,988 | |
Cost of sales, excluding depreciation and amortization | | — | | 149,507 | | 3,357,052 | | — | | 3,506,559 | |
| | — | | (144,788 | ) | 318,021 | | (1,804 | ) | 171,429 | |
Operating expenses | | | | | | | | | | | |
Depreciation of property, plant and equipment | | — | | 2,987 | | 61,981 | | — | | 64,968 | |
General and administrative | | — | | 24,688 | | 2,051 | | (1,804 | ) | 24,935 | |
Amortization of intangible assets | | — | | — | | 29,177 | | — | | 29,177 | |
Stock based compensation | | — | | 4,629 | | — | | — | | 4,629 | |
Gain on sale of assets | | — | | — | | (37 | ) | — | | (37 | ) |
Other non-operating expenses (income) | | | | | | | | | | | |
Accretion expense | | — | | — | | 787 | | — | | 787 | |
Foreign exchange gain | | — | | (30,038 | ) | (9,842 | ) | — | | (39,880 | ) |
Loss from equity investments | | — | | 688 | | 226 | | — | | 914 | |
Loss (income) from investment in subsidiaries | | (155 | ) | (233,334 | ) | — | | 233,489 | | — | |
Interest expense, net | | — | | 98,949 | | 178 | | — | | 99,127 | |
| | (155 | ) | (131,431 | ) | 84,521 | | 231,685 | | 184,620 | |
| | | | | | | | | | | |
Income (loss) before income taxes | | 155 | | (13,357 | ) | 233,500 | | (233,489 | ) | (13,191 | ) |
Income tax recovery | | — | | (13,512 | ) | 166 | | — | | (13,346 | ) |
Net income | | 155 | | 155 | | 233,334 | | (233,489 | ) | 155 | |
Dividends on preferred shares | | (14,034 | ) | — | | — | | — | | (14,034 | ) |
Movement in retained earnings (deficit) for the year | | $ | (13,879 | ) | $ | 155 | | $ | 233,334 | | $ | (233,489 | ) | $ | (13,879 | ) |
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(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Statement of Cashflow
Successor | |
| | Year ended December 31, 2010 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
Cash provided by (used in) | | | | | | | | | | | |
Operating activities | | | | | | | | | | | |
Net income | | $ | 155 | | $ | 155 | | $ | 233,334 | | $ | (233,489 | ) | $ | 155 | |
Items not affecting cash | | | | | | | | | | | |
Depreciation and amortization | | — | | 2,987 | | 91,158 | | — | | 94,145 | |
Stock based compensation | | — | | 4,629 | | — | | — | | 4,629 | |
Future income taxes | | — | | (13,588 | ) | (2,537 | ) | — | | (16,125 | ) |
Accretion expense | | — | | — | | 787 | | — | | 787 | |
Accretion related to long-term debt | | — | | 6,628 | | — | | — | | 6,628 | |
Gain on disposal of assets | | — | | — | | (37 | ) | — | | (37 | ) |
Unrealized gain on financial instruments | | — | | — | | (1,373 | ) | — | | (1,373 | ) |
Foreign exchange gain on long-term debt | | — | | (36,760 | ) | — | | — | | (36,760 | ) |
Other | | — | | 18 | | 351 | | — | | 369 | |
Income from investment in subsidiaries | | (155 | ) | (233,334 | ) | — | | 233,489 | | — | |
Net change in non-cash working capital | | — | | (80,518 | ) | 79,760 | | — | | (758 | ) |
Net cash (used in) provided by operating activities | | — | | (349,783 | ) | 401,443 | | — | | 51,660 | |
Investing activities | | | | | | | | | | | |
Purchase of property, plant and equipment | | — | | (9,993 | ) | (51,689 | ) | — | | (61,682 | ) |
Equity investments | | — | | (3,050 | ) | — | | — | | (3,050 | ) |
Proceeds on disposal of assets | | — | | — | | 2,750 | | — | | 2,750 | |
Increase in long-term prepaid and other assets | | — | | 609 | | 104 | | — | | 713 | |
Acquisitions, net of cash acquired | | — | | (48,606 | ) | (184,140 | ) | — | | (232,746 | ) |
Net change in non-cash working capital | | — | | 1,308 | | 10,972 | | — | | 12,280 | |
Net cash used in investing activities | | — | | (59,732 | ) | (222,003 | ) | — | | (281,735 | ) |
Financing activities | | | | | | | | | | | |
Proceeds from long-term debt, net of debt discount | | — | | 200,888 | | — | | — | | 200,888 | |
Payment of debt issue costs | | — | | (6,544 | ) | — | | — | | (6,544 | ) |
Proceeds from credit facility | | — | | 241,626 | | — | | — | | 241,626 | |
Repayment of credit facility | | | | (223,126 | ) | — | | — | | (223,126 | ) |
Receipt (payment) of partnership income | | — | | 189,021 | | (189,021 | ) | — | | — | |
Net cash provided by (used in) financing activities | | — | | 401,865 | | (189,021 | ) | — | | 212,844 | |
Effect of exchange rate on cash and cash equivalents | | — | | (50 | ) | (1,757 | ) | — | | (1,807 | ) |
Net decrease in cash and cash equivalents | | — | | (7,700 | ) | (11,338 | ) | — | | (19,038 | ) |
Cash and cash equivalents — beginning of year | | — | | 11,893 | | 14,370 | | — | | 26,263 | |
Cash and cash equivalents — end of year | | $ | — | | $ | 4,193 | | $ | 3,032 | | $ | — | | $ | 7,225 | |
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Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Balance Sheet
Successor | |
| | December 31, 2009 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
| | | | | | | | | | | |
Assets | | | | | | | | | | | |
Current assets | | | | | | | | | | | |
Cash and cash equivalents | | $ | — | | $ | 11,893 | | $ | 14,370 | | $ | — | | $ | 26,263 | |
Accounts receivable | | — | | 99,899 | | 432,913 | | (216,947 | ) | 315,865 | |
Income taxes receivable | | — | | 10,405 | | 645 | | — | | 11,050 | |
Inventories | | — | | — | | 113,688 | | — | | 113,688 | |
Current portion of future income taxes | | — | | 1,509 | | — | | — | | 1,509 | |
Prepaid expenses | | — | | 2,285 | | 2,902 | | — | | 5,187 | |
Total current assets | | — | | 125,991 | | 564,518 | | (216,947 | ) | 473,562 | |
Future income taxes | | — | | 5,225 | | — | | — | | 5,225 | |
Long-term prepaid expenses and other assets | | — | | 11,440 | | 23,992 | | — | | 35,432 | |
Property, plant and equipment | | — | | 14,797 | | 584,029 | | — | | 598,826 | |
Investment in subsidiaries | | 588,644 | | 1,176,299 | | — | | (1,763,716 | ) | — | |
Intangible assets | | — | | — | | 126,955 | | — | | 126,955 | |
Goodwill | | — | | 35,727 | | 398,167 | | — | | 433,894 | |
Total assets | | $ | 588,644 | | $ | 1,368,252 | | $ | 1,697,661 | | $ | (1,980,663 | ) | $ | 1,673,894 | |
| | | | | | | | | | | |
Liabilities | | | | | | | | | | | |
Current liabilities | | | | | | | | | | | |
Credit facility | | $ | — | | $ | 25,000 | | $ | — | | $ | — | | $ | 25,000 | |
Accounts payable and accrued charges | | — | | 163,689 | | 321,532 | | (216,947 | ) | 268,274 | |
Income taxes payable | | — | | 8,443 | | — | | — | | 8,443 | |
Current portion of future income taxes | | — | | 839 | | — | | — | | 839 | |
Total current liabilities | | — | | 197,971 | | 322,532 | | (216,947 | ) | 302,556 | |
Asset retirement obligation | | — | | — | | 8,287 | | — | | 8,287 | |
Long-term debt | | — | | 553,942 | | — | | — | | 553,942 | |
Other long-term liabilities | | — | | 1,506 | | 14,586 | | — | | 16,092 | |
Future income taxes | | — | | 201,723 | | 2,650 | | — | | 204,373 | |
Shareholder’s equity | | 588,644 | | 413,110 | | 1,350,606 | | (1,763,716 | ) | 588,644 | |
Total liabilities and shareholder’s equity | | $ | 588,644 | | $ | 1,368,252 | | $ | 1,697,661 | | $ | (1,980,663 | ) | $ | 1,673,894 | |
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Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Statement of Income (Loss)
Successor | |
| | Year ended December 31, 2009 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
| | | | | | | | | | | |
Revenue | | $ | — | | $ | 4,086 | | $ | 3,450,951 | | $ | (900 | ) | $ | 3,454,137 | |
Cost of sales, excluding depreciation and amortization | | — | | 136,893 | | 3,155,528 | | — | | 3,292,421 | |
| | — | | (132,807 | ) | 295,423 | | (900 | ) | 161,716 | |
Operating expenses | | | | | | | | | | | |
Depreciation of property, plant and equipment | | — | | 2,899 | | 53,665 | | — | | 56,564 | |
General and administrative | | — | | 24,683 | | 948 | | (900 | ) | 24,731 | |
Amortization of intangible assets | | — | | — | | 25,747 | | — | | 25,747 | |
Stock based compensation | | — | | 8,957 | | — | | — | | 8,957 | |
Gain on sale of assets | | — | | — | | (90 | ) | — | | (90 | ) |
Impairment of goodwill and intangibles | | — | | — | | 114,115 | | — | | 114,115 | |
Other non-operating expenses (income) | | | | | | | | | | | |
Accretion expense | | — | | — | | 785 | | — | | 785 | |
Foreign exchange gain | | — | | (91,835 | ) | (846 | ) | — | | (92,681 | ) |
Debt extinguishment costs | | — | | 18,517 | | — | | — | | 18,517 | |
Loss from equity investments | | — | | — | | 54 | | — | | 54 | |
Loss (income) from investment in subsidiaries | | 62,949 | | (103,350 | ) | — | | 40,401 | | — | |
Interest expense, net | | — | | 80,698 | | (83 | ) | — | | 80,615 | |
| | 62,949 | | (59,431 | ) | 194,295 | | 39,501 | | 237,314 | |
Income (loss) before income taxes | | (62,949 | ) | (73,376 | ) | 101,128 | | (40,401 | ) | (75,598 | ) |
Income tax recovery | | — | | (10,427 | ) | (2,222 | ) | — | | (12,649 | ) |
Net income (loss) | | (62,949 | ) | (62,949 | ) | 103,350 | | (40,401 | ) | (62,949 | ) |
Dividends on preferred shares | | (12,409 | ) | — | | — | | — | | (12,409 | ) |
Movement in retained earnings (deficit) for the year | | $ | (75,358 | ) | $ | (62,949 | ) | $ | 103,350 | | $ | (40,401 | ) | $ | (75,358 | ) |
F-70
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Statement of Cashflow
Successor | |
| | Year ended December 31, 2009 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
Cash provided by (used in) | | | | | | | | | | | |
Operating activities | | | | | | | | | | | |
Net income (loss) | | $ | (62,949 | ) | $ | (62,949 | ) | $ | 103,350 | | $ | (40,401 | ) | $ | (62,949 | ) |
Items not affecting cash | | | | | | | | | | | |
Depreciation and amortization | | — | | 2,899 | | 79,412 | | — | | 82,311 | |
Stock based compensation | | — | | 8,957 | | — | | — | | 8,957 | |
Future income taxes | | — | | (10,159 | ) | (2,264 | ) | — | | (12,423 | ) |
Accretion expense | | — | | — | | 785 | | — | | 785 | |
Accretion related to long-term debt | | — | | 11,890 | | — | | — | | 11,890 | |
Gain on disposal of assets | | — | | — | | (90 | ) | — | | (90 | ) |
Unrealized loss on financial instruments | | — | | — | | 9,692 | | — | | 9,692 | |
Impairment of goodwill and intangibles | | — | | — | | 114,115 | | — | | 114,115 | |
Foreign exchange gain on long-term debt | | — | | (97,991 | ) | — | | — | | (97,991 | ) |
Debt extinguishment costs | | — | | 18,517 | | — | | — | | 18,517 | |
Other | | — | | (178 | ) | (521 | ) | — | | (699 | ) |
Income from investment in subsidiaries | | 62,949 | | (103,350 | ) | — | | 40,401 | | — | |
Net change in non-cash working capital | | — | | 67,968 | | (138,013 | ) | — | | (70,045 | ) |
Net cash (used in) provided by operating activities | | — | | (164,396 | ) | 166,466 | | — | | 2,070 | |
Investing activities | | | | | | | | | | | |
Purchase of property, plant and equipment | | — | | (1,935 | ) | (35,032 | ) | — | | (36,967 | ) |
Equity investments | | — | | (6,643 | ) | — | | — | | (6,643 | ) |
Proceeds on disposal of assets | | — | | — | | 998 | | — | | 998 | |
Increase in long-term prepaid and other assets | | — | | (1,835 | ) | (4,022 | ) | — | | (5,857 | ) |
Acquisitions, net of cash acquired | | — | | (6,900 | ) | (8,265 | ) | — | | (15,165 | ) |
Net change in non-cash working capital | | — | | (31,103 | ) | (466 | ) | — | | (31,569 | ) |
Net cash used in investing activities | | — | | (48,416 | ) | (46,787 | ) | — | | (95,203 | ) |
Financing activities | | | | | | | | | | | |
Proceeds from long-term debt, net of debt discounts | | — | | 605,723 | | — | | — | | 605,723 | |
Payment of debt issue costs | | — | | (15,904 | ) | — | | — | | (15,904 | ) |
Repayments of bridge loans | | — | | (606,040 | ) | — | | — | | (606,040 | ) |
Proceeds from credit facility | | — | | 25,000 | | — | | — | | 25,000 | |
Receipt (payment) of partnership income | | — | | 207,296 | | (207,296 | ) | — | | — | |
Net change in non-cash working capital | | — | | (2,335 | ) | — | | — | | (2,335 | ) |
Net cash provided by (used in) financing activities | | — | | 213,740 | | (207,296 | ) | — | | 6,444 | |
Net increase (decrease) in cash and cash equivalents | | — | | 928 | | (87,617 | ) | — | | (86,689 | ) |
Cash and cash equivalents — beginning of year | | — | | 10,965 | | 101,987 | | — | | 112,952 | |
Cash and cash equivalents — end of year | | $ | — | | $ | 11,893 | | $ | 14,370 | | $ | — | | $ | 26,263 | |
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Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Statement of Income
Successor | |
| | Period from December 13, 2008
to December 31, 2008 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
| | | | | | | | | | | |
Revenue | | $ | — | | $ | 8,073 | | $ | 127,398 | | $ | — | | $ | 135,471 | |
Cost of sales, excluding depreciation and amortization | | — | | 18,010 | | 106,962 | | — | | 124,972 | |
| | — | | (9,937 | ) | 20,436 | | — | | 10,499 | |
Operating expenses | | | | | | | | | | | |
Depreciation of property, plant and equipment | | — | | 130 | | 3,428 | | — | | 3,558 | |
General and administrative | | — | | 615 | | — | | — | | 615 | |
Amortization of intangible assets | | — | | — | | 1,323 | | — | | 1,323 | |
Loss on sale of assets | | — | | — | | 18 | | — | | 18 | |
Other non-operating expenses (income) | | | | | | | | | | | |
Accretion expense | | — | | — | | 22 | | — | | 22 | |
Foreign exchange loss (gain) | | — | | (5,069 | ) | 582 | | — | | (4,487 | ) |
Loss from equity investments | | — | | — | | 21 | | — | | 21 | |
Income from investment in subsidiaries | | (4,980 | ) | (14,887 | ) | — | | 19,867 | | — | |
Interest expense, net | | — | | 3,430 | | (11 | ) | — | | 3,419 | |
| | (4,980 | ) | (15,781 | ) | 5,383 | | 19,867 | | 4,489 | |
Income before income taxes | | 4,980 | | 5,844 | | 15,053 | | (19,867 | ) | 6,010 | |
Income tax provision | | — | | 864 | | 166 | | — | | 1,030 | |
Net income | | 4,980 | | 4,980 | | 14,887 | | (19,867 | ) | 4,980 | |
Dividends on preferred shares | | (625 | ) | — | | — | | — | | (625 | ) |
Movement in retained earnings for the period | | $ | 4,355 | | $ | 4,980 | | $ | 14,887 | | $ | (19,867 | ) | $ | 4,355 | |
F-72
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
| | Condensed Consolidated Statement of Cashflow
Successor | |
| | Period from December 13, 2008
to December 31, 2008 | |
| | Gibson | | The Issuers | | Other
Guarantors | | Eliminations | | Consolidated | |
Cash provided by (used in) | | | | | | | | | | | |
Operating activities | | | | | | | | | | | |
Net income | | $ | 4,980 | | $ | 4,980 | | $ | 14,887 | | $ | (19,867 | ) | $ | 4,980 | |
Items not affecting cash | | | | | | | | | | | |
Depreciation and amortization | | — | | 130 | | 4,751 | | — | | 4,881 | |
Future income taxes | | — | | 750 | | — | | — | | 750 | |
Accretion expense | | — | | — | | 22 | | — | | 22 | |
Accretion related to long-term debt | | — | | 395 | | — | | — | | 395 | |
Loss on disposal of assets | | — | | — | | 18 | | — | | 18 | |
Unrealized loss (gain) on financial instruments | | — | | 3,211 | | (1,754 | ) | — | | 1,457 | |
Foreign exchange gain on long-term debt | | — | | (5,069 | ) | — | | — | | (5,069 | ) |
Other | | — | | — | | (63 | ) | — | | (63 | ) |
Income from investment in subsidiaries | | (4,980 | ) | (14,887 | ) | — | | 19,867 | | — | |
Net change in non-cash working capital | | — | | (56,513 | ) | 85,979 | | — | | 29,466 | |
Net cash provided by (used in) operating activities | | — | | (67,003 | ) | 103,840 | | — | | 36,837 | |
Investing activities | | | | | | | | | | | |
Purchase of property, plant and equipment | | — | | (84 | ) | (2,898 | ) | — | | (2,982 | ) |
Proceeds on disposal of assets | | — | | — | | 695 | | — | | 695 | |
Increase in long-term prepaid and other assets | | — | | — | | (1,697 | ) | — | | (1,697 | ) |
Acquisitions, net of cash acquired | | — | | (982,365 | ) | — | | — | | (982,365 | ) |
Net change in non-cash working capital | | — | | 32,712 | | 2,047 | | — | | 34,759 | |
Net cash used in investing activities | | — | | (949,737 | ) | (1,853 | ) | — | | (951,590 | ) |
Financing activities | | | | | | | | | | | |
Proceeds from long-term debt | | — | | 672,476 | | — | | — | | 672,476 | |
Payment of debt issue costs | | — | | (27,720 | ) | — | | — | | (27,720 | ) |
Proceeds from issuance of common shares | | — | | 380,656 | | — | | — | | 380,656 | |
Net change in non-cash working capital | | — | | 2,293 | | — | | — | | 2,293 | |
Net cash provided by financing activities | | — | | 1,027,705 | | — | | — | | 1,027,705 | |
| | | | | | | | | | | |
Net increase in cash and cash equivalents | | — | | 10,965 | | 101,987 | | — | | 112,952 | |
Cash and cash equivalents — beginning of period | | — | | — | | — | | — | | — | |
Cash and cash equivalents — end of period | | $ | — | | $ | 10,965 | | $ | 101,987 | | $ | — | | $ | 112,952 | |
F-73
Table of Contents
Gibson Energy Holding ULC
Notes to Consolidated Financial Statements
(tabular amounts in thousands of Canadian dollars, except where noted)
27 Subsequent Events
On January 7, 2011, the Company completed the disposition of its Edmonton North Terminal to Pembina Midstream Limited Partnership for cash consideration of approximately $54,000,000 plus certain other non-cash consideration. The terminal was a remotely operated facility located in Edmonton, Alberta, with a capacity of 310,000 barrels and was included in the operations of our Marketing segment. As part of the consideration received, the Company secured important pipeline assets and connections that will provide access to crude oil streams within the Edmonton area and assumed obligations related to these assets.
F-74
