Management’s Discussion and Analysis at October 27, 2011
The following Management’s Discussion and Analysis (“MD&A”) is provided to assist readers in understanding CE Franklin Ltd.’s (“CE Franklin” or the “Company”) financial performance and position during the periods presented and significant trends that may impact future performance of CE Franklin. This MD&A should be read in conjunction with the Company’s condensed interim consolidated financial statements for the three and nine month period ended September 30, 2011 and the MD&A and the consolidated financial statements for the three and six month periods ended June 30, 2011 and the three month period ended March 31, 2011 (the Company’s first financial statements under IFRS) and the MD&A and consolidated financial statements for the year ended December 31, 2010. All amounts are expressed in Canadian dollars and are in accordance with International Financial Reporting Standards (“IFRS”), except where otherwise noted. The September 30, 2011 condensed interim consolidated financial statements are prepared under IFRS. Consequently the comparative figures for 2010 and the Company’s statement of financial position as at January 1, 2010 have been restated from accounting principles generally accepted in Canada (“Canadian GAAP”) to comply with IFRS. The reconciliations from the previously published Canadian GAAP financial statements are summarized in Note 3 to the condensed interim consolidated financial statements, and there were no material differences. In addition, IFRS 1 on first time adoption allows certain exemptions from retrospective application of IFRS in the opening statement of financial position. Where these exemptions have been used they have also been explained in Note 3 to the condensed interim consolidated financial statements.
Overview
CE Franklin is a leading distributor of pipe, valves, flanges, fittings, production equipment, tubular products and other general industrial supplies primarily to the oil and gas industry through its 43 branches situated in towns and cities that serve oil and gas fields of the western Canadian sedimentary basin. In addition, the Company distributes similar products to the oil sands, refining, and petrochemical industries and non-oilfield related industries such as forestry and mining.
The Company’s branch operations service over 3,000 customers by providing the right materials where and when they are needed, and for the best value. Our branches, supported by our centralized Distribution Centre in Edmonton, Alberta, stock over 25,000 stock keeping units sourced from over 2,000 suppliers. This supply chain infrastructure enables us to provide our customers with the products they need on a same day or over-night basis. Our centralized inventory and procurement capabilities allow us to leverage our scale to enable industry leading hub and spoke purchasing and logistics capabilities. Our branches are also supported by services provided by the Company’s corporate office in Calgary, Alberta including sales, marketing, product expertise, logistics, invoicing, credit and collection and other business services.
The Company’s shares trade on the TSX (“CFT”) and NASDAQ (“CFK”) stock exchanges. Schlumberger Limited (“Schlumberger”), a major oilfield service company based in Paris, France, owns approximately 56% of the Company’s shares.
Business Strategy
The Company is pursuing the following strategies to grow its business profitably:
·
Expand the reach and market share serviced by the Company’s distribution network. The Company is focusing its sales efforts and product offering on servicing complex, multi-location needs of large and emerging customers in the energy sector. Organic growth is expected to be complemented by selected acquisitions over time.
·
Expand production equipment service capability to capture more of the product life cycle requirements for the equipment the Company sells such as down hole pump repair, oilfield engine maintenance, well optimization and on site project management. This will differentiate the Company’s service offering from its competitors and deepen relationships with its customers.
·
Expand oil sands and industrial project and Maintenance, Repair and Operating Supplies (“MRO”) business by leveraging our existing supply chain infrastructure, product and project expertise.
·
Increase the resourcing of customer project sales quotation and order fulfillment services provided by our Distribution Centre to augment local branch capacity to address seasonal and project driven fluctuations in customer demand. By doing so, we aim to increase our capacity flexibility and improve operating efficiency while providing consistent service.
Business Outlook
Oil and gas industry activity in 2011 is expected to remain at or above 2010 levels for the remainder of the year. Natural gas prices remain depressed as North American production capacity and inventory levels continue to dominate demand. Natural gas capital expenditure activity is focused on the emerging shale gas plays in northeastern British Columbia and liquid rich gas plays in northwestern Alberta where the Company has a strong market position. Conventional and heavy oil economics are attractive at current price levels leading to continuing activity in eastern Alberta and southeast Saskatchewan. Oil sands project announcements continue at current oil price levels. Approximately 50% to 60% of the Company’s total revenues are driven by our customers’ capital expenditure requirements. CE Franklin’s revenues are expected to increase modestly in 2012 as the oil and gas industry activity levels remain relatively consistent with 2011 levels.
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Gross profit margins are expected to remain under pressure as customers that produce natural gas focus on reducing their costs to maintain acceptable project economics and due to continued aggressive oilfield supply industry competition as industry activity levels remain below the last five year average. The Company will continue to manage its cost structure to protect profitability while maintaining service capacity and advancing strategic initiatives.
Over the medium to longer term, the Company’s strong financial and competitive positions should enable profitable growth of its distribution network through the expansion of its product lines, supplier relationships and capability to service additional oil and gas and other industrial end use markets.
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Third Quarter Operating Results | |
The following table summarizes CE Franklin’s results of operations: | |
(In millions of Canadian Dollars except per share data) | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30 | | Nine Months Ended September 30 |
| 2011 | | 2010 | | 2011 | | 2010 |
Revenues | 140.5 | 100.0 | % | | 132.2 | 100.0 | % | | 392.0 | 100.0 | % | | 353.9 | 100.0 | % |
Cost of Sales | (116.6) | (83.0) | % | | (113.0) | (85.5) | % | | (326.6) | (83.3) | % | | (299.5) | (84.6) | % |
Gross Profit | 23.9 | 17.0 | % | | 19.2 | 14.5 | % | | 65.4 | 16.7 | % | | 54.4 | 15.4 | % |
| | | | | | | | | | | | | | | |
Selling, general and | | | | | | | | | | | | | | | |
administrative expenses | (17.8) | (12.7) | % | | (15.5) | (11.7) | % | | (51.2) | (13.1) | % | | (45.8) | (12.9) | % |
Foreign exchange and other | 1.6 | 1.1 | % | | 0.1 | 0.1 | % | | 1.8 | 0.5 | % | | - | - | % |
EBITDA(1) | 7.7 | 5.5 | % | | 3.8 | 2.9 | % | | 16.0 | 4.1 | % | | 8.6 | 2.5 | % |
Depreciation | (0.6) | (0.4) | % | | (0.6) | (0.5) | % | | (1.8) | (0.5) | % | | (1.8) | (0.5) | % |
Interest | (0.2) | (0.1) | % | | (0.1) | (0.1) | % | | (0.4) | (0.1) | % | | (0.5) | (0.1) | % |
Earnings before tax | 6.9 | 4.9 | % | | 3.1 | 2.3 | % | | 13.8 | 3.5 | % | | 6.3 | 1.9 | % |
Income tax expense | (2.1) | (1.5) | % | | (0.9) | (0.7) | % | | (4.0) | (1.0) | % | | (2.0) | (0.6) | % |
Net earnings | 4.8 | 3.4 | % | | 2.2 | 1.7 | % | | 9.8 | 2.5 | % | | 4.3 | 1.3 | % |
| | | | | | | | | | | | | | |
Net earnings per share | | |
Basic | | | | | $ | 0.27 | | $ | 0.12 | | $ | 0.56 | | $ 0.24 |
Diluted | | | | | $ | 0.26 | | $ | 0.12 | | $ | 0.54 | | $ 0.24 |
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Weighted average number of shares outstanding (000's) |
Basic | | | | | | 17,537 | | | 17,461 | | | 17,507 | | 17,518 |
Diluted | | | | | | 18,165 | | | 17,783 | | | 18,142 | | 17,838 |
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|
(1) EBITDA represents net earnings before interest, taxes, depreciation and amortization. EBITDA is a supplemental non-GAAP financial measure used by management, as well as industry analysts, to evaluate operations. Management believes that EBITDA, as presented, represents a useful means of assessing the performance of the Company’s ongoing operating activities, as it reflects the Company’s earnings trends without showing the impact of certain charges. The Company is also presenting EBITDA and EBITDA as a percentage of revenues because it is used by management as supplemental measures of profitability. The use of EBITDA by the Company has certain material limitations because it excludes the recurring expenditures of interest, income tax, and depreciation expenses. Interest expense is a necessary component of the Company’s expenses because the Company borrows money to finance its working capital and capital expenditures. Depreciation expense is a necessary component of the Company’s expenses because the Company is required to pay cash to acquire equipment to generate revenues. Management compensates for these limitations to the use of EBITDA by using EBITDA as only a supplementary measure of profitability. EBITDA is not used by management as an alternative to net earnings, as an indicator of the Company’s operating performance, as an alternative to any other measure of performance in conformity with generally accepted accounting principles or as an alternative to cash flow from operating activities as a measure of liquidity. A reconciliation of EBITDA to net earnings is provided within the table above. Not all companies calculate EBITDA in the same manner and EBITDA does not have a standardized meaning prescribed by GAAP. Accordingly, EBITDA, as the term is used herein, is unlikely to be comparable to EBITDA as reported by other entities.
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Third Quarter Results
Net earnings for the third quarter of 2011, were $4.8 million, an increase of $2.6 million from the third quarter of 2010. Revenues were $140.5 million, an increase of $8.3 million (6%) from the third quarter of 2010. Industry activity continued to improve and is focused on oil, oil sands and liquid rich natural gas plays. Well completions increased 34% compared to the third quarter of 2010. Capital project business revenue grew $6.2 million year over year due to improved industry activity levels. Gross profits increased by $4.7 million (24%) due to the increase in revenues and improved gross profit margins year over year. Average gross profit margins were consistent with the second quarter of 2011 but improved over the third quarter 2010 average gross profit margin, as increased purchasing levels contributed to higher volume rebate income. Selling, general and administrative expenses increased by $2.3 million (15%) to $17.8 million for the quarter as compensation and operating costs have increased in response to higher revenue levels. During the quarter, the Company moved its head office location within downtown Calgary and as a consequence recorded a one time lease charge of $0.7 million in relation to its old head office lease obligations net of expected sublease revenue. The Company also recorded an unrealized foreign exchange gain of $1.0 million in the quarter on foreign exchange contracts used to manage currency exposure on US denominated product purchases. The weighted average number of shares outstanding during the third quarter was consistent with the prior year period as the rise in share price during the last year has limited the activity occurring under the normal course issuer bid program. Net earnings per share (basic) was $0.27 in the third quarter of 2011, compared to net earnings of $0.12 per share in the third quarter of 2010.
Year to date Results
Net Income for the nine months ended September 30, 2011 at $9.8 million was more than double the net income for the same prior year period. Revenues were $392.0 million, an increase of $38.1 million (11%) over the comparable 2010 period due to improvements in capital project and maintenance repair and operating revenues. Well completions have increased 32% year over year as industry activity continues to build. Gross profit was up $10.9 million (20%) due to the increase in revenues combined with an increase in vendor rebate income due to increased purchasing levels. Selling, general and administrative expenses increased by $5.4 million (12%) to $51.2 million for the nine months ended for the same reasons they were higher in the third quarter. Income taxes increased by $1.9 million for the nine months ended September 30, 2011 compared to the prior year period due to higher pre-tax earnings. The weighted average number of shares outstanding (basic) during the third quarter was consistent with the prior year period as the rise in share price during the last year has limited the activity occurring under the normal course issuer bid program. Net earnings per share (basic) was $0.56 for the nine months ended September 30, 2011, compared to $0.24 earned in the same prior year period.
Revenues
Revenues for the quarter ended September 30, 2011, were $140.5 million, an increase of 6% from the quarter ended September 30, 2010, as detailed above in the “Third Quarter Results” discussion.
Oil and gas commodity prices are a key driver of industry capital project activity as commodity prices directly impact the economic returns realized by oil and gas companies. The Company uses oil and gas well completions and average rig counts as industry activity measures to assess demand for oilfield equipment used in capital projects. Oil and gas well completions require the products sold by the Company to complete a well and bring production on stream and are a general indicator of energy industry activity levels. Average drilling rig counts are also used by management to assess industry activity levels as the number of rigs in use ultimately drives well completion requirements. Well completion, rig count and commodity price information for the three and nine month periods ended September 30, 2011 and 2010 are provided in the table below.
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| | | Q3 Average | | % | | | YTD Average | | % |
| | | 2011 | | | 2010 | | change | | | 2011 | | | 2010 | | change |
Gas - Cdn. $/gj (AECO spot) | $ | 3.67 | | $ | 3.55 | | 3 | % | | $ | 3.77 | | $ | 4.12 | | (8) | % |
Oil - Cdn. $/bbl (synthetic crude) | $ | 99.16 | | $ | 77.37 | | 28 | % | | $ | 102.74 | | $ | 79.30 | | 30 | % |
Average rig count | | 456 | | | 325 | | 40 | % | | | 392 | | | 309 | | 27 | % |
Well completions: | | | | | | | | | | | | | | | | | |
| Oil | | 2,699 | | | 1,484 | | 82 | % | | | 6,685 | | | 3,916 | | 71 | % |
| Gas | | 796 | | | 1,127 | | (29) | % | | | 3,436 | | | 3,738 | | (8) | % |
Total well completions | | 3,495 | | | 2,611 | | 34 | % | | | 10,121 | | | 7,654 | | 32 | % |
| | | | | | | | | | | | | | | | | | |
Average statistics are shown except for well completions. |
Sources:Oil and Gas prices – First Energy Capital Corp.; Rig count data – CAODC; well completion data – Daily Oil Bulletin |
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(in millions of Cdn. $) | Three months ended September 30 | | Nine months ended September 30 |
| 2011 | | 2010 | | 2011 | | 2010 |
End use revenue demand | $ | % | | $ | % | | $ | % | | $ | % |
Capital projects | 72.9 | 52 | % | | 66.7 | 50 | % | | 205.7 | 52 | % | | 182.4 | 52 | % |
Maintenance, repair and operating | | | | | | | | | | | | | | | |
supplies ("MRO") | 67.6 | 48 | % | | 65.5 | 50 | % | | 186.3 | 48 | % | | 171.5 | 48 | % |
Total Revenues | 140.5 | 100 | % | | 132.2 | 100 | % | | 392.0 | 100 | % | | 353.9 | 100 | % |
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Note:Capital project end use revenues are defined by the Company as consisting of the tubular and 80% of pipe, flanges and fittings; and valves and accessories product revenues respectively; MRO revenues are defined by the Company as consisting of pumps and production equipment, production services; general product and 20% of pipes, flanges and fittings; and valves and accessory product revenues respectively. | |
Revenues from capital project related products were $72.9 million in the third quarter of 2011, an increase of 9% ($6.2 million) from the third quarter of 2010. Total well completions increased by 34% in the third quarter of 2011 and the average working rig count increased by 40% compared to the prior year period. Gas wells comprised 23% of the total wells completed in western Canada in the third quarter of 2011 compared to 43% in the third quarter of 2010. Spot gas prices ended the third quarter at $3.52 per GJ (AECO) a decrease of 4% from third quarter average prices. Oil prices ended the third quarter at $90.34 per bbl (Synthetic Crude) a decrease of 9% from the third quarter average. Depressed gas prices are expected to continue to negatively impact gas drilling activity over the remainder of 2011, which in turn is expected to constrain demand for the Company’s products. Natural gas customers continue to utilize a high level of competitive bid activity to procure the products they require in an effort to reduce their costs. The Company is addressing this industry trend by pursuing initiatives focused on improving revenue quotation processes and increasing the operating flexibility and efficiency of its branch network. The Company is well positioned to support customers who are pursuing oil plays and more particularly tight oil plays.
MRO product revenues are related to overall oil and gas industry production levels and tend to be more stable than capital project revenues. MRO product revenues for the quarter ended September 30, 2011 increased by $2.1 million (3%) to $67.6 million compared to the quarter ended September 30, 2010 and comprised 48% of the Company’s total revenues (2010 – 50%).
The Company’s strategy is to grow profitability by focusing on its core western Canadian oilfield product distribution business, complemented by an increase in the product life cycle services provided to its customers and the focus on the emerging oil sands capital project and MRO revenues opportunities. Revenues from these initiatives to date are provided below:
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| Q3 2011 | | Q3 2010 | | YTD 2011 | | YTD 2010 | |
Revenues($millions) | $ | % | | $ | % | | $ | % | | $ | % | |
Oilfield | 115.1 | 82 | % | | 104.2 | 79 | % | | 327.2 | 84 | % | | 292.5 | 84 | % | |
Oil sands | 18.9 | 13 | % | | 23.7 | 18 | % | | 48.3 | 12 | % | | 49.8 | 14 | % | |
Production services | 6.5 | 5 | % | | 4.3 | 3 | % | | 16.5 | 4 | % | | 11.6 | 3 | % | |
Total Revenues | 140.5 | 100 | % | | 132.2 | 100 | % | | 392.0 | 100 | % | | 353.9 | 100 | % | |
Revenues from oilfield products to conventional western Canada oil and gas end use applications were $115.1 million for the third quarter of 2011, backing out tubular product sales, which were down $0.7 million in the third quarter year over year, oilfield revenue was up 12.2%. This increase was driven by the 34% increase in well completions compared to the prior year period.
Revenues from oil sands end use applications were $18.9 million in the third quarter, a decrease of $4.8 million (20%) compared to $23.7 million in the third quarter of 2010 reflecting lower turnaround activity and no tailing pipe sales in 2011. The Company continues to position its major project execution capability and the Fort McMurray branch to penetrate this emerging market for capital projects and MRO products.
Production service revenues were $6.5 million in the third quarter of 2011, a 51% increase from the $4.3 million of revenues in the third quarter of 2010, reflecting improved oil production economics resulting in increased customer maintenance activities.
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Gross Profit | | | | | | | | | | | | | | | |
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| Q3 2011 | | Q3 2010 | | YTD 2011 | | YTD 2010 |
Gross profit($ millions) | $ | 23.9 | | | $ | 19.2 | | | $ | 65.4 | | | $ | 54.5 | |
Gross profit margin as a % of revenues | | 17.0 | % | | | 14.5 | % | | | 16.7 | % | | | 15.4 | % |
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Gross profit composition by product revenue category: | | | | | | | | | | | | | | | |
Tubulars | | 1 | % | | | 3 | % | | | 3 | % | | | 2 | % |
Pipe, flanges and fittings | | 33 | % | | | 28 | % | | | 30 | % | | | 29 | % |
Valves and accessories | | 21 | % | | | 20 | % | | | 21 | % | | | 20 | % |
Pumps, production equipment and services | | 17 | % | | | 15 | % | | | 15 | % | | | 14 | % |
General | | 28 | % | | | 34 | % | | | 31 | % | | | 35 | % |
Total gross profit | | 100 | % | | | 100 | % | | | 100 | % | | | 100 | % |
Gross profit was $23.9 million in the third quarter of 2011, an increase of $4.7 million (24%) from the third quarter of 2010 due to increased revenues and average gross profit margins compared to the prior year period. Gross profit margins for the quarter remained consistent with the second quarter 2011 levels and were better than the prior year period at 16.9% as increased purchasing levels contributed to higher volume rebate income. In the quarter the Company effectively passed along price increases related to increasing steel costs from our suppliers to our customers. Increased pipe, flanges and fittings and valves and accessories gross profit composition was due to improved gross profit margins. The decrease in tubular gross profit composition reflects larger lower margin sales and the disposal of surplus tubular inventory.
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Selling, General and Administrative (“SG&A”) Costs | |
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($millions) | Q3 2011 | | Q3 2010 | | YTD 2011 | | YTD 2010 | |
| $ | | % | | $ | | % | | $ | | % | | $ | | % | |
People Costs | 10.6 | | 60 | | 8.9 | | 57 | | 30.9 | | 61 | | 26.5 | | 58 | |
Facility and office costs | 4.3 | | 24 | | 3.3 | | 21 | | 11.5 | | 22 | | 10.1 | | 22 | |
Selling Costs | 1.7 | | 10 | | 1.8 | | 12 | | 4.2 | | 8 | | 4.5 | | 10 | |
Other | 1.2 | | 6 | | 1.5 | | 10 | | 4.6 | | 9 | | 4.7 | | 10 | |
SG&A costs | 17.8 | | 100 | | 15.5 | | 100 | | 51.2 | | 100 | | 45.8 | | 100 | |
SG&A costs as % of revenues | 12.7 | % | | | 11.7 | % | | | 13.1 | % | | | 12.9 | % | | |
SG&A costs increased $2.3 million (15%) in the third quarter of 2011 from the prior year period and represented 12.7% of revenues compared to 11.7% in the prior year period. The $2.3 million increase in expenses was attributable to higher people costs reflecting a 6% increase in employee head count to service the additional sales volumes and higher incentive compensation costs reflecting the improved profit performance of the business year over year. Facility and office costs also increased in the quarter as the Company moved its head office location within downtown Calgary and as a consequence recorded a one time lease charge of $0.7 million for its old head office lease obligations net of expected sublease revenue.
Depreciation Expense
Depreciation expense of $0.6 million in the third quarter of 2011 was comparable to the third quarter of 2010.
Interest Expense
Interest expense of $0.2 million in the third quarter of 2011 was higher than the prior year as fees related to the renewal of the Company’s banking facility were expensed in the period.
Foreign Exchange Gain and other
Foreign exchange gains and other in the quarter amounted to $1.6 million as the significant weakening of the Canadian dollar at the end of the quarter increased the translation gains from US denominated net working capital assets. The Company recognized a $1.0 million unrealized foreign currency gain on $14.2 million of foreign currency forward contracts it had outstanding at quarter end. As at September 30, 2011, a one percent change in the Canadian dollar relative to the US dollar would decrease or increase the Company’s annual net income by $0.1 million.
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Income Tax Expense
The Company’s effective tax rate for the third quarter of 2011 was 29.8%, down 0.5% from the third quarter of 2010 as the decline in the statutory rate was partially offset by the impact of permanent differences. The current effective tax rate is higher than the statutory rate due to the impact of non-deductible items and other adjustments. Substantially all of the Company’s tax provision is currently payable.
Summary of Quarterly Financial Data
The selected quarterly financial data is presented in Canadian dollars and in accordance with IFRS. This information is derived from the Company’s unaudited quarterly financial statements. As noted above the September 30, 2011 interim consolidated financial statements have been prepared under IFRS. The comparative figures shown in the table below for 2010 have been restated from Canadian GAAP. The reconciliations from Canadian GAAP to IFRS have been completed and there were no material differences noted. The conversion from Canadian GAAP to IFRS is further discussed in Note 3 of the condensed interim consolidated financial statements.
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(in millions of Cdn. $ except per share data) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Q4 | | Q1 | | Q2 | | Q3 | | Q4 | | Q1 | | Q2 | | Q3 |
Unaudited | 2009 (2) | | 2010 | | 2010 | | 2010 | | 2010 | | 2011 | | 2011 | | 2011 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenues | | 93.0 | | | | 121.9 | | | | 99.9 | | | | 132.2 | | | | 135.6 | | | | 137.7 | | | | 113.9 | | | | 140.5 | |
Gross Profit | | 15.3 | | | | 19.7 | | | | 15.6 | | | | 19.2 | | | | 20.5 | | | | 22.3 | | | | 19.3 | | | | 23.9 | |
Gross Profit % | | 16.5 | % | | | 16.1 | % | | | 15.6 | % | | | 14.5 | % | | | 15.1 | % | | | 16.2 | % | | | 16.9 | % | | | 17.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EBITDA | | 0.6 | | | | 4.1 | | | | 0.7 | | | | 3.8 | | | | 3.8 | | | | 5.3 | | | | 3.1 | | | | 7.7 | |
EBITDA as a % of revenues | | 0.6 | % | | | 3.4 | % | | | 0.7 | % | | | 2.9 | % | | | 2.8 | % | | | 3.8 | % | | | 2.7 | % | | | 5.5 | % |
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Net earnings (loss) | | (0.5) | | | | 2.2 | | | | (0.1) | | | | 2.2 | | | | 1.6 | | | | 3.4 | | | | 1.7 | | | | 4.8 | |
Net earnings (loss) as a % of | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
revenues | | (0.5) | % | | | 1.8 | % | | | (0.1) | % | | | 1.7 | % | | | 1.2 | % | | | 2.5 | % | | | 1.5 | % | | | 3.4 | % |
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Net earnings (loss) per share | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | $ | (0.03) | | | $ | 0.13 | | | $ | (0.01) | | | $ | 0.12 | | | $ | 0.09 | | | $ | 0.19 | | | | 0.10 | | | $ | 0.27 | |
| Diluted | $ | (0.03) | | | $ | 0.12 | | | $ | (0.01) | | | $ | 0.12 | | | $ | 0.09 | | | $ | 0.19 | | | | 0.09 | | | $ | 0.26 | |
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Net working capital(1) | | 136.6 | | | | 113.9 | | | | 111.8 | | | | 129.0 | | | | 125.7 | | | | 120.1 | | | | 136.5 | | | | 134.6 | |
Long term debt/bank | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
operating loan(1) | | 26.8 | | | | 1.4 | | | | 0.3 | | | | 14.4 | | | | 6.4 | | | | 0.3 | | | | 12.2 | | | | 5.8 | |
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Total well completions | | 1,576 | | | | 2,846 | | | | 2,197 | | | | 2,611 | | | | 4,760 | | | | 3,861 | | | | 2,765 | | | | 3,495 | |
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(1) Net working capital and long term debt/bank operating loan amounts are as at quarter end |
(2) Prepared using Canadian GAAP |
The Company’s revenue levels are affected by weather conditions. As warm weather returns in the spring each year, the winter’s frost comes out of the ground rendering many secondary roads incapable of supporting the weight of heavy equipment until they have dried out. In addition, many exploration and production areas in northern Canada are accessible only in the winter months when the ground is frozen. An exceptionally wet second quarter in 2011 had some impact on customer capital programs in the third quarter. As a result, the first and fourth quarters typically represent the busiest time for oil and gas industry activity and the highest revenue activity for the Company. Revenue levels drop dramatically during the second quarter until such time as roads have dried and road bans have been lifted. This typically results in a significant reduction in earnings during the second quarter, as the decline in revenue typically out paces the decline in SG&A costs as the majority of the Company’s SG&A costs are fixed in nature. Net working capital (defined as current assets less cash and cash equivalents, accounts payable and accrued liabilities, income taxes payable and other current liabilities) and borrowing levels follow similar seasonal patterns as revenue.
Liquidity and Capital Resources
The Company’s primary internal source of liquidity is cash flow from operating activities before net changes in non-cash working capital balances related to operations. Cash flow from operating activities and the Company’s $60.0 million revolving term credit facility are used to finance the Company’s net working capital, capital expenditures and acquisitions.
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As at September 30, 2011 the Company had $5.8 million in borrowings under its revolving term credit facility, a net decrease of $0.6 million from December 31, 2010. Borrowing levels have decreased due to the Company generating $10.8 million in cash flow from operating activities before net changes in working capital. This was offset by $2.1 million in capital and other expenditures and $0.7 million for the purchase of shares to resource stock compensation obligations and the repurchase of shares under the Company’s Normal Course Issuer Bid (“NCIB”).
As at September 30, 2010, there were $14.1 million in borrowings under the Company’s debt facility, a decrease of $12.5 million from December 31, 2009. Borrowing levels have decreased since December 31, 2009 due to the Company generating $7.5 million in cash flow from operating activities before net changes in working capital and a $7.7 million reduction in net working capital. This was offset by $1.1 million in capital and other expenditures, $0.4 million for the settlement of share obligations and $1.2 million for the purchase of shares to resource stock compensation obligations and the repurchase of shares under the Company’s NCIB.
Net working capital was $134.6 million at September 30, 2011, an increase of $8.9 million from December 31, 2010. Accounts receivable increased by $3.1 million to $96.1 million at September 30, 2011 from December 31, 2010 due to the 4% increase in revenues in the third quarter compared to the fourth quarter of 2010, partially offset by a weaker Days Sales Outstanding (“DSO”). DSO in the third quarter of 2011 was 58 days compared to 56 days in the fourth quarter of 2010 and 58 days in the third quarter of 2010. DSO is calculated using average revenues per day for the quarter compared to the period end accounts receivable balance. Inventory increased by $7.7 million at September 30, 2011 from December 31, 2010. Inventory turns for the third quarter of 2011 decreased to 4.5 turns compared to 4.9 turns in the fourth quarter of 2010. Inventory turns are calculated using cost of goods sold for the quarter on an annualized basis compared to the period end inventory balance. The Company continues to adjust its investment in inventory to align with anticipated industry activity levels and supplier lead times in order to improve inventory turnover efficiency. Accounts payable and accrued liabilities increased by $6.6 million (10%) to $70.0 million at September 30, 2011 from December 31, 2010 due to the seasonal increase in activity.
Capital expenditures in the third quarter of 2011 were $1.1 million, $0.5 million higher than the prior year period and were comprised primarily of vehicles, warehouse equipment replacements and branch improvements. In the quarter the Company disposed of a surplus building and some surplus vehicles for net proceeds of $0.4 million.
The Company has a $60.0 million revolving term credit facility that matures in July 2014 (the “Credit Facility”). The loan facility bears interest based on floating interest rates and is secured by a general security agreement covering all assets of the Company. The maximum amount available under the Credit Facility is subject to a borrowing base formula applied to accounts receivable and inventories. The Credit Facility requires the Company to maintain the ratio of its debt to debt plus equity at less than 40%. As at September 30, 2011, this ratio was 3%. The Company must also maintain coverage of its net operating cash flow as defined in the Credit Facility agreement over interest expense for the trailing twelve month period of greater than 1.25 times. As at September 30, 2011 this ratio was 24.9 times. The Credit Facility contains certain other covenants with which the Company is in compliance. As at September 30, 2011 the Company had available undrawn borrowing capacity of $54.5 million under this Credit facility.
Contractual Obligations
There have been no material changes in off-balance sheet contractual commitments since June 30, 2011.
| | | | |
Capital Stock |
As at September 30, 2011 and 2010, the following shares and securities convertible into shares were outstanding: |
| | | | |
(millions) | | September 30, 2011 | | September 30, 2010 |
| | Shares | | Shares |
Shares outstanding | | 17.5 | | 17.4 |
Stock options | | 0.6 | | 1.1 |
Share unit plan obligations | | 0.7 | | 0.6 |
Shares outstanding and issuable | | 18.8 | | 19.1 |
The weighted average number of shares outstanding during the third quarter of 2011 was 17.5 million, which was consistent with the prior year period as the rise in the Company’s share price during the last year has limited the activity occurring under the normal course issuer bid program. The diluted weighted average number of shares outstanding was 18.2 million, which is also consistent with the prior year quarter.
The Company has established an independent trust to purchase common shares of the Company on the open market to resource share unit plan obligations. During the three and nine month periods ended September 30, 2011, 500 common shares and 75,500 common shares were acquired by the trust at an average cost per share of $8.28 and $9.26 per share respectively (three and nine months ended September 30, 2010 – 92,500 and 129,300 common shares at an average cost per share of $6.79 and $6.83 respectively). As at September 30, 2011, the trust held 481,726 shares (September 30, 2010 – 471,610 shares).
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On December 21, 2010, the Company announced the renewal of the NCIB, to purchase up to 850,000 common shares representing approximately 5% of its outstanding common shares. Shares may be purchased up to December 31, 2011. As at September 30, 2011 the Company had purchased 3,102 shares at an average cost of $7.56 per share (September 30, 2010 – 57,878 shares at an average cost of $6.61 per share).
Critical Accounting Estimates
There have been no material changes to critical accounting estimates since December 31, 2010. The Company is not aware of any environmental or asset retirement obligations that could have a material impact on its operations.
Change in Accounting Policies
Transition to International Financial Reporting Standards (“IFRS”)
In February 2008, the Canadian Accounting Standards Board confirmed that the basis for financial reporting by Canadian publicly accountable enterprises will change from Canadian GAAP to IFRS effective for January 1, 2011, including the preparation and reporting of one year of comparative figures. This change is part of a global shift to provide consistency in financial reporting in the global marketplace.
Over the transition period the Company assessed the differences between Canadian GAAP and IFRS. A risk based approach was used to identify possibly significant differences based on possible financial impact and complexity. As described in Note 3 to the condensed interim consolidated financial statements no material differences were identified. As such there are no reconciling items that materially changed the reporting requirements upon the transition from Canadian GAAP to IFRS. Similarly, no significant information system changes were required in order to adopt IFRS.
IFRS 1 allows first time adopters of IFRS to take advantage of a number of voluntary exemptions from the general principal of retroactive restatement. In adopting IFRS, the Company did take advantage of the following voluntary exemptions under IFRS 1.
Business Combinations
The Company has not applied IFRS 3, the Business Combinations standard to acquisitions of subsidiaries that occurred before January 1, 2010, the Company’s transition date to IFRS. As such there is no retrospective change in accounting for business combinations. The Company used this exemption to simplify its IFRS conversion plan and improve comparability between its Canadian GAAP statements and its IFRS statements.
Borrowing Costs
IAS 23 requires that borrowing costs directly attributable to the acquisition, construction or production of a qualifying asset (one that takes a substantial period of time to get ready for use or sale) be capitalized as part of the cost of that asset. The option of immediately expensing those borrowing costs has been removed. The Company has elected to account for such transactions on a go forward basis, and as such there is no retrospective change in accounting for borrowing standards. The Company used this exemption to simplify its IFRS conversion plan and improve comparability between its Canadian GAAP statements and its IFRS statements.
Stock Options
The Company has assessed and quantified the difference in accounting for stock based compensation under IFRS compared to Canadian GAAP and has deemed the difference to be immaterial. The Company has elected to not apply IFRS 2 to share based payments granted and fully vested before the Company’s date of transition to IFRS. The Company used this exemption to simplify its IFRS conversion plan and improve comparability between its Canadian GAAP statements and its IFRS statements.
As part of the transition to IFRS the Company established that the carrying value of its property and equipment were substantially equivalent between IFRS and Canadian GAAP and therefore the Company has continued to carry its property and equipment at the historic costs model as was used under Canadian GAAP in these statements.
Controls and Procedures
Internal control over financial reporting (“ICFR”) is designed to provide reasonable assurance regarding the reliability of the Company’s financial reporting and its compliance with IFRS in its financial statements. The President and Chief Executive Officer and the Vice President and Chief Financial Officer of the Company have evaluated whether there were changes to its ICFR during the nine months ended September 30, 2011 that have materially affected or are reasonably likely to materially affect the ICFR. No such changes were identified through their evaluation.
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Risk Factors
The Company is exposed to certain business and market risks including risks arising from transactions that are entered into the normal course of business, which are primarily related to interest rate changes and fluctuations in foreign exchange rates. During the reporting period, no events or transactions since the year ended December 31, 2010 have occurred that would materially change the business and market risk information disclosed in the Company’s Form 20F.
Forward Looking Statements
The information in the MD&A may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, that address activities, events, outcomes and other matters that CE Franklin plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this MD&A, including those in under the caption“Risk Factors”.
Forward-looking statements appear in a number of places and include statements with respect to, among other things:
·
forecasted oil and gas industry activity levels in 2011 and beyond;
·
planned capital expenditures and working capital and availability of capital resources to fund capital expenditures and working capital;
·
the Company’s future financial condition or results of operations and future revenues and expenses;
·
the Company’s business strategy and other plans and objectives for future operations;
·
fluctuations in worldwide prices and demand for oil and gas;
·
fluctuations in the demand for the Company’s products and services.
Should one or more of the risks or uncertainties described above or elsewhere in this MD&A occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements expressed or implied, included in this MD&A and attributable to CE Franklin are qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that CE Franklin or persons acting on its behalf might issue. CE Franklin does not undertake any obligation to update any forward-looking statements to reflect events or circumstance after the date of filing this MD&A, except as required by law.
Additional Information
Additional information relating to CE Franklin, including its third quarter 2011 Management Discussion and Analysis and interim consolidated financial statements and its Form 20-F / Annual Information Form, is available under the Company’s profile on the SEDAR website atwww.sedar.com and atwww.cefranklin.com.
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