Management’s Discussion and Analysis at October 28, 2010
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 discussion should be read in conjunction with the Company’s interim consolidated financial statements for the three and nine month period ended September 30, 2010, the interim consolidated financial statements and MD&A for the three and six month period ended June 30, 2010 and the three month period ended March 31, 2010 and the MD&A and the consolidated financial statements for the year ended December 31, 2009. All amounts are expressed in Canadian dollars and in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”), excep t otherwise noted.
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 49 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 required 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 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, a major oilfield service company based in Paris France, owns approximately 55% 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-site needs of large and emerging customers in the energy sector. Organic growth is expected to be complemented by selected acquisitions.
·
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 is expected to 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.
Business Outlook
Oil and gas industry activity in 2010 continues to increase modestly from the decade-low levels experienced in 2009. Natural gas prices remain depressed as North American production capacity and inventory levels currently dominate demand. Natural gas capital expenditure activity is focused on the emerging shale gas plays in north eastern British Columbia where the Company has a strong market position. Conventional and heavy oil economics are reasonable at current price levels leading to moderate activity in eastern Alberta and south east Saskatchewan. The reduction in Alberta royalty rates announced during the second quarter is expected to result in improved drilling economics and industry activity. Industry well completions, which drive demand for the Company’s capital project related products, have begun to accelerate in response to the significant increase in rig count activity compared to the prior year period. Oil sands project announcements are gaining momentum with the recovery in oil prices and access to capital markets. Approximately 50% to 60% of the Company’s total sales are driven by our customer’s capital expenditure requirements. CE Franklin’s revenues are expected to increase modestly in the remainder of 2010 and into 2011 due to increased oil and gas industry activity and the expansion of the Company’s product lines.
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Sales margins are expected to remain under pressure as natural gas exploration customer’s focus on reducing their costs to maintain acceptable project economics, as well as continued aggressive oilfield supply industry competition and deflation in certain product lines. 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 will 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.
Third Quarter Operating Results
The following table summarizes CE Franklin’s results of operations:
| | | | | | | | |
| (In millions of Cdn. Dollars except per share data and may not add due to rounding to millions) | | |
| | Three Months Ended September 30 | Nine Months Ended September 30 |
| | 2010 | | 2009 | 2010 | 2009 |
| Sales | 132.2 | 100.0% | 94.1 | 100.0% | 353.9 | 100.0% | 344.0 | 100.0% |
| Cost of Sales | (113.0) | (85.5)% | (76.7) | (81.5)% | (299.5) | (84.6)% | (282.7) | (82.2)% |
| Gross profit | 19.2 | 14.5% | 17.4 | 18.5% | 54.4 | 15.4% | 61.3 | 17.8% |
| |
| Selling, general and | | | | | | | | |
| administrative | | | | | | | | |
| expenses | (15.5) | (11.7)% | (17.0) | (18.1)% | (45.8) | (12.9)% | (49.7) (14.4)% |
| other | 0.1 | 0.1% | 0.1 | 0.1% | - | 0.0% | 0.1 | 0.0% |
| EBITDA(1) | 3.8 | 2.9% | 0.5 | 0.5% | 8.6 | 2.5% | 11.7 | 3.4% |
| Amortization | (0.6) | (0.5)% | (0.6) | (0.6)% | (1.8) | (0.5)% | (1.7) | (0.5)% |
| Interest | (0.1) | (0.1)% | (0.3) | (0.3)% | (0.5) | (0.1)% | (0.7) | (0.2)% |
| Income (loss) before | | | | | | | | |
| taxes | 3.1 | 2.4% | (0.4) | (0.5)% | 6.3 | 1.9% | 9.3 | 2.7% |
| Income tax expense | (0.9) | (0.7)% | 0.6 | 0.6% | (2.0) | (0.6)% | (2.5) | (0.7)% |
| Net income | 2.2 | 1.7% | 0.2 | 0.1% | 4.3 | 1.3% | 6.8 | 2.0% |
| |
| Net income per share | | | | | | | | |
| Basic | $ 0.12 | | $ 0.01 | | $ 0.24 | | $ 0.38 | |
| Diluted | $ 0.12 | | $ 0.01 | | $ 0.24 | | $ 0.38 | |
| |
| Weighted average | | | | | | | | |
| number of shares | | | | | | | | |
| outstanding (000's) | | | | | | | | |
| Basic | 17,461 | | 17,647 | | 17,518 | | 17,795 | |
| Diluted | 17,783 | | 17,908 | | 17,838 | | 18,036 | |
(1)
EBITDA represents net income 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 sales 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 amortization expenses. Interest expense is a necessary component of the Company’s expenses because the Company borr ows money to finance its working capital and capital income taxes. Amortization expense is a necessary component of the Company’s expenses because the Company is required to pay cash equipment to generate sales. 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 incomes, 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 income 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
The Company recorded net income for the third quarter of 2010 of $2.2 million, an increase of $2.0 million from the third quarter of 2009. Third quarter sales, which are seasonally stronger than the second quarter, were $132.2 million, an increase of $38.1 million (40%) from the third quarter of 2009. Improvements in and stability of oil prices, as well as improved general economic conditions have lead to higher activity levels in the oil and gas industry, which in turn has lead to improved oilfield and oil sands sales compared to the prior year. Increased oilfield supply sales were driven by a 78% increase in industry well completions over the prior year period. Gross profit was up $1.8 million (10%) as the impact of increased sales activity was partially offset by a 4.0% decline in average sales margins from the prior year period. Lower average margins were attributable to an increased mix of lower margin oil sands sales and the highly competitive oilfield supply industry environment. Selling, general and administrative expenses decreased by $1.5 million (9%) to $15.5 million compared to the prior year period due to the one-time integration costs associated with the acquisition of a Western Canadian oilfield supply competitor in June 2009 (the “Oilfield Supply Acquisition”) and lower agent commission costs. Income taxes increased by $1.6 million in the third quarter of 2010 compared to the prior year period due to higher pre-tax earnings. The weighted average number of shares outstanding (basic) during the third quarter decreased by 0.2 million shares (1%) from the prior year period principally due to shares purchased for cancellation pursuant to the Company’s Normal Course Issuer Bid (“NCIB”). Net income per share (basic) was $0.12 in the third quarter of 2010, compared to net income per share of $0.01 earned in the prior year period.
Year to Date Results
Net income for the first three quarters of 2010 was $4.3 million, down $2.6 million from the first three quarters of 2009. Sales were $353.9 million, an increase of $9.9 million (3%) from the first three quarters of 2009. Higher sales reflect sales contributed from the Oilfield Supply Acquisition and increased industry demand driven by the 14% increase in well completions over the prior year period. Partially offsetting this was the absence of a $32.4 million sale of oil sands pipe in the second quarter of 2009 and the rollover of tubular and other steel product prices and margins during 2009. Gross profit was down $6.9 million (11%) as the increase in sales was offset by a 2.4% decline in average margins from the prior year period. The highly competitive oilfield supply industry environment continues to impact margins. Selling, general and administrative expenses decreased by $3.8 million (8%) to $45.8 million for the first three quarters of the year due to the absence of $1.5 million of costs to integrate the Oilfield Supply Acquisition in 2009, and lower compensation, agent commission and bad debt costs incurred in 2010. Income taxes decreased by $0.5 million in the first three quarters of 2010 compared to the prior year period due to lower pre-tax earnings. The weighted average number of shares outstanding (basic) during the first nine months decreased by 0.3 million shares (2%) from the prior year period principally due to shares purchased for cancellation pursuant to the Company’s NCIB. Net income per share (basic) was $0.24 in the first three quarters of 2010, compared to $0.38 earned in the first three quarters of 2009.
Sales
Sales for the third quarter ended September 30, 2010, were $132.2 million, up 40% from the quarter ended September 30, 2009, as detailed above in the “Third Quarter results” discussion.
| | | | | | | | |
| (in millions of Cdn. $) | | | | | | | | |
| | Three months ended Sept 30 | Nine months ended Sept 30 |
| | 2010 | | 2009 | | 2010 | | 2009 | |
| End use sales demand | $ % | $ % | $ % | $ % |
| Capital projects | 66.7 | 50 | 48.4 | 51 | 182.4 | 52 | 199.5 | 58 |
| Maintenance, repair and | | | | | | | | |
| operating supplies (MRO) | 65.5 | 50 | 45.7 | 49 | 171.5 | 48 | 144.5 | 42 |
| Total Sales | 132.2 | 100 | 94.1 | 100 | 353.9 | 100 | 344.0 | 100 |
Note:Capital project end use sales are defined by the Company as consisting of the tubular and 80% of pipe, flanges and fittings; and valves and accessories product sales respectively; MRO Sales 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 sales respectively.
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The relative level of oil and gas commodity prices are a key driver of industry capital project activity as product 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, 2010 and 2009 are provided in the table below.
| | | | | | | |
| | Q3 Average | | % | YTD Average | % |
| | 2010 | | 2009 | change | 2010 | 2009 | change |
| Gas - Cdn. $/gj (AECO spot) | $ 3.54 | $ 2.97 | 19% | $ 4.12 | $ 3.79 | 9% |
| Oil - Cdn. $/bbl (synthetic crude) | $ 77.37 | $ 73.99 | 5% | $ 79.30 | $ 65.93 | 20% |
| |
| Average rig count | 325 | | 178 | 83% | 309 | 197 | 57% |
| Well completions: | | | | | | | |
| Oil | 1,484 | | 822 | 81% | 3,916 | 2,198 | 78% |
| Gas | 1,127 | | 646 | 74% | 3,738 | 4,491 | (17)% |
| Total well completions | 2,611 | | 1,468 | 78% | 7,654 | 6,689 | 14% |
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
Sales of capital project related products were $66.7 million in the third quarter of 2010, up 38% ($18.3 million) from the third quarter of 2009 due to increased industry capital project activity. Total well completions increased by 78% in the third quarter of 2010 and the average working rig count increased by 83% compared to the prior year period. Gas wells comprised 43% of the total wells completed in western Canada in the third quarter of 2010 compared to 44% in the third quarter of 2009. Spot gas prices ended the third quarter at $3.55 per GJ (AECO), consistent with third quarter average prices. Oil prices ended the third quarter at $81.17 per bbl (Synthetic Crude), which is a 5% increase from the third quarter average price. Depressed gas prices are expected to continue to negatively impact gas drilling activity over the remainder of 2010 and into 2011, which in turn is expected to constra in demand for the Company’s products.
MRO product sales are related to overall oil and gas industry production levels and tend to be more stable than capital project sales. MRO product sales for the quarter ended September 30, 2010 were $65.5 million which is a $19.8 million increase from the $45.7 million in the quarter ended September 30, 2009 and comprised 50% of the Company’s total sales.
The Company’s strategy is to grow profitability by focusing on its core western Canadian oilfield product distribution business, complemented by an increase in the product life cycle services provided to its customers and the focus on the emerging oil sands capital project and MRO sales opportunities. Sales results of these initiatives to date are provided below:
| | | | | | | | |
| | Q3 2010 | | Q3 2009 | YTD 2010 | | YTD 2009 |
| Sales ($millions) | $ % | $ % | $ % | $ % |
| Oilfield | 104.2 | 79 | 87.9 | 93 | 292.5 | 83 | 282.3 | 82 |
| Oil sands | 23.7 | 18 | 3.4 | 4 | 49.8 | 14 | 54.4 | 16 |
| Production services | 4.3 | 3 | 2.8 | 3 | 11.6 | 3 | 7.3 | 2 |
| Total sales | 132.2 | 100 | 94.1 | 100 | 353.9 | 100 | 344.0 | 100 |
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Sales of oilfield products to conventional western Canada oil and gas end use applications were $104.2 million for the third quarter of 2010, up 19% from the third quarter of 2009. This increase was driven by the 78% increase in well completions compared to the prior year period.
Sales to oil sands end use applications were $23.7 million in the third quarter, an increase of $20.3 million compared to the third quarter of 2009. On a year to date basis, sales are below 2009 levels as the second quarter of 2009 included a $32.4 million oil sands pipe sale that did not repeat in 2010. The Company continues to position its sales focus, Edmonton Distribution Centre and Fort McMurray branch to penetrate this emerging market for capital project and MRO products.
Production service sales were $4.3 million in the third quarter of 2010, an increase of $1.5 million compared to the third quarter of 2009, reflecting improved oil production economics resulting in increased customer maintenance activities that were deferred in 2009.
Gross Profit
| | | | | |
| | Q3 2010 | Q3 2009 | YTD 2010 | YTD 2009 |
| |
| Gross profit(millions) | $ 19.2 | $ 17.4 | $ 54.5 | $ 61.3 |
| Gross profit margin as a % of sales | | 14.5% | 18.5% | 15.4% | 17.8% |
| |
| Gross profit composition by product sales category: | | | | |
| Tubulars | | 3% | 3% | 2% | 6% |
| Pipe, flanges and fittings | | 28% | 28% | 29% | 32% |
| Valves and accessories | | 20% | 21% | 20% | 20% |
| Pumps, production equipment and services | | 15% | 12% | 14% | 11% |
| General | | 34% | 36% | 35% | 31% |
| Total gross profit | | 100% | 100% | 100% | 100% |
Gross profit was $19.2 million in the third quarter of 2010, an increase of $1.8 million (10%) from the third quarter of 2009 as the increase in sales activity was partially offset by a 4.0% decline in average sales margins. Gross profit margins declined from 18.5% in the third quarter of 2009 to 14.5% in the third quarter of 2010. Lower sales margins reflect an increased mix of lower margin oil sands sales combined with a highly competitive oilfield supply industry. Lower year to date tubular gross profit composition reflects the rollover of tubular prices and margins that commenced in the second quarter of 2009.
Selling, General and Administrative (“SG&A”) Costs
| | | | | | | | |
| ($millions) | Q3 2010 | | Q3 2009 | YTD 2010 | YTD 2009 |
| | $ % | $ % | $ % | $ % |
| People costs | 8.9 | 57 | 9.3 | 55 | 26.5 | 58 | 28.0 | 56 |
| Facility and office costs | 3.3 | 21 | 3.4 | 20 | 10.1 | 22 | 10.1 | 20 |
| Selling costs | 1.8 | 12 | 2.4 | 14 | 4.5 | 10 | 6.0 | 13 |
| Other | 1.5 | 10 | 1.9 | 11 | 4.7 | 10 | 5.6 | 11 |
| SG&A costs | 15.5 | 100 | 17.0 | 100 | 45.8 | 100 | 49.7 | 100 |
| SG&A costs as % of sales | 12% | | 18% | | 13% | | 14% | |
SG&A costs have decreased $1.5 million (9%) in the third quarter of 2010 from the prior year period and represented 12% of sales compared to 18% in the prior year period. Lower people costs reflect one-time stock based compensation costs recorded in the prior year period associated with the implementation of a cash settlement mechanic to the Company’s stock option plan. Selling costs in the quarter are lower than the prior year period due to a $0.6 million reduction in agent commissions (Year to date = $1.0 million reduction). Other costs are lower in the third quarter of 2010 due to one-time costs incurred to integrate the Oilfield Supply Acquisition in the prior year period. The balance of the selling cost decline on a year to date basis is due to the recovery of a previously written off bad debt.
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Amortization Expense
Amortization expense of $0.6 million in the third quarter of 2010 was comparable to the third quarter of 2009.
Interest Expense
Interest expense of $0.1 million in the third quarter of 2010 declined $0.2 million from the prior year period due to lower average borrowing levels.
Foreign Exchange (Gain) Loss
Foreign exchange gains on United States dollar denominated product purchases and net working capital liabilities were $0.1 million in the third quarter of 2010 and were consistent with the prior year quarter.
Income Tax Expense
The Company’s effective tax rate for the third quarter of 2010 was 30.3% compared to 146.1% in the third quarter of 2009. The high effective tax rate in the prior year quarter resulted from implementing a cash settlement mechanism to the Company’s stock option plan. Stock option expense was previously non-deductible for income tax purposes. Additionally, non-deductible items had a greater impact on the effective tax rate in the third quarter of 2009 due to the decrease in pre-tax income compared to the current year period. 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 Canadian GAAP. This information is derived from the Company’s unaudited quarterly financial statements.
| | | | | | | | |
| (in millions of Cdn. dollars except per share data) | | | | | | | |
| Unaudited | Q4 | Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 |
| | 2008 | 2009 | 2009 | 2009 | 2009 | 2010 | 2010 | 2010 |
| Sales | $ 161.2 | $ 140.7 | $ 109.1 | $ 94.1 | $ 93.0 | $ 121.9 | $ 99.9 | $ 132.2 |
| Gross profit | 33.9 | 26.4 | 17.5 | 17.4 | 15.3 | 19.7 | 15.6 | 19.2 |
| Gross profit % | 21.0% | 18.8% | 16.0% | 18.5% | 16.5% | 16.1% | 15.6% | 14.5% |
| EBITDA | 14.3 | 9.6 | 1.7 | 0.5 | 0.6 | 4.1 | 0.7 | 3.8 |
| EBITDA as a % of sales | 8.9% | 6.8% | 1.6% | 0.5% | 0.6% | 3.4% | 0.7% | 2.9% |
| Net income (loss) | 8.8 | 6.0 | 0.6 | 0.2 | (0.5) | 2.2 | (0.1) | 2.2 |
| Net income (loss) as a % of sales | 5.5% | 4.3% | 0.5% | 0.2% | (0.5%) | 1.8% | (0.1%) | 1.6% |
| Net income (loss) per share | | | | | | | | |
| Basic | $ 0.48 | $ 0.33 | $ 0.04 | $ 0.01 | ($0.03) | $ 0.13 | ($0.01) | $ 0.12 |
| Diluted | $ 0.47 | $ 0.33 | $ 0.03 | $ 0.01 | ($0.03) | $ 0.12 | ($0.01) | $ 0.12 |
| |
| Net working capital(1) | 142.8 | 153.2 | 137.0 | 131.1 | 136.6 | 113.9 | 111.8 | 129.0 |
| Long term debt /Bank operating | | | | | | | | |
| loan(1) | 34.9 | 40.2 | 25.3 | 21.3 | 26.5 | 1.1 | 0.0 | 14.4 |
| |
| Total well completions | 6,971 | 3,947 | 1,274 | 1,468 | 1,576 | 2,846 | 2,197 | 2,611 |
| |
| (1)Net working capital, bank operating loan and long term debt amounts are as at quarter end. | | | |
The Company’s sales 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. As a result, the first and fourth quarters typically represent the busiest time for oil and gas industry activity and the highest sales activity for the Company. Sales 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 sales typically out paces the decline in SG&A costs as the majority of the Company’s SG&A co sts are fixed in nature. Net working capital (defined as current assets excluding cash, less accounts payable and accrued liabilities, income taxes payable and other current liabilities, excluding the bank operating loan) and bank operating loan borrowing levels follow similar seasonal patterns as sales.
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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. Cash flow from operating activities and the Company’s revolving term credit facility are used to finance the Company’s net working capital, capital expenditures and acquisitions.
As at September 30, 2010, there were $14.1 million of borrowings under the Company’s revolving term bank loan, 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 non-cash working capital balances 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.
As at September 30, 2009, borrowings under the Company’s bank revolving term bank loan were $21.3 million, a decrease of $13.6 million from December 31, 2008. Borrowing levels decreased due to the Company generating $10.3 million in cash flow from operating activities, before net changes in non-cash working capital balances and a $19.8 million reduction in net working capital excluding the impact of the cash settled options and inventory addition related to the acquisition of the Acquired Business. This was offset by $2.3 million in capital and other expenditures, $11.3 million related to the Oilfield Supply Acquisition and $2.9 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 $129.0 million at September 30, 2010, a decrease of $7.6 million from December 31, 2009. Accounts receivable increased by $24.3 million (36%) to $91.7 million at September 30, 2010 from December 31, 2009 due mainly to a 42% increase in sales partially offset by a 3% improvement in Days Sales Outstanding (“DSO”). DSO in the third quarter of 2010 was 58 days compared to 60 days in the fourth quarter of 2009 and 57 days in the third quarter of 2009. DSO is calculated using average sales per day for the quarter compared to the period end accounts receivable balance. Inventory decreased by $6.6 million (6%) at September 30, 2010 from December 31, 2009. Inventory turns for the third quarter of 2010 improved to 4.7 turns compared to 3.0 turns in the fourth quarter of 2009 and 2.9 turns in the third quarter of 2009. 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 $25.7 million (66%) to $64.0 million at September 30, 2010 from December 31, 2009, responsive to increased purchasing and sales levels.
Capital expenditures in the third quarter of 2010 were $0.6 million, a reduction of $0.1 million compared to the prior year period. The majority of the capital expenditures in both periods were directed towards branch facility expansions and maintenance.
On July 8, 2010, a new $60.0 million revolving term bank credit facility was entered into. The credit facility matures in July 2013 and provides lower borrowing costs and improved covenant flexibility. Previously the Company had a $60 million, 364 day bank operating facility. The maximum amount available to borrow under the Credit Facility is subject to a borrowing base formula applied to accounts receivable and inventories. Under the terms of the Credit Facility, the Company must maintain the ratio of its debt to debt-plus-equity at less than 40% (9% at September 30, 2010) and coverage of net operating free cash flow as defined in the Credit Facility agreement over interest expense for the trailing 12 month period of greater than 1.25 times (9.1 times at September 30, 2010). The Credit Facility contains certain other covenants, which the Company is in compliance with.
Contractual Obligations
There have been no material changes in off-balance sheet contractual commitments since December 31, 2009.
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Capital Stock
As at September 30, 2010 and 2009, the following shares and securities convertible into shares were outstanding:
| | |
| (millions) | September 30, 2010 September 30, 2009 |
| | Shares | Shares |
| Shares outstanding | 17.4 | 17.6 |
| Stock options | 1.1 | 1.2 |
| Share unit plan obligations | 0.6 | 0.5 |
| Shares outstanding and issuable | 19.1 | 19.3 |
The weighted average number of shares outstanding during the third quarter of 2010 was 17.5 million, a decrease of 0.2 million shares from the prior year’s third quarter due principally to the purchases of common shares under its NCIB and to resource share unit plan obligations. The diluted weighted average number of shares outstanding was 17.8 million, a decrease of 0.1 million shares from the prior year’s third 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, 2010, 50,000 and 179,300 common shares were acquired by the trust at an average cost per share of $6.75 and $6.79 respectively. (Three and nine months ended September 30, 2009 – nil and 75,000 at an average cost per share of $5.23). As at September 30, 2009, the trust held 471,610 shares (September 30, 2009 – 354,683 shares).
On December 23, 2009, the Company announced the renewal of the NCIB, to purchase up to 880,000 common shares representing approximately 5% of its outstanding common shares. Shares may be purchased up to December 31, 2010. As at September 30, 2010, the Company had purchased 57,878 shares at an average cost of $6.61 per share (September 30, 2009 – 530,587 shares at an average cost of $5.14 per share).
The Company settles exercises of stock options through payment of cash in order to manage share dilution while resourcing its long term incentive plan on a tax efficient basis. As a result, the Company’s stock option obligations (subject to vesting) are classified as a current liability (September 30, 2010 - $1.7 million) based on the positive difference between the Company’s closing stock price at period end and the underlying option exercise price. The offset to the generation of the current liability is contributed surplus, up to the cumulative expensed Black Scholes valuation, and compensation expense for the excess of the intrinsic value over the cumulative expensed Black Scholes value. The liability is marked to market at each period end, with any adjustment allocated to the relevant account as detailed above. On March 4, 2010, the federal government introduced its 2010 budget which contained provis ions which if enacted, could result in future stock option settlement payments no longer being deductible by the Company for tax purposes. This would result in the accounting write off of approximately $0.5 million of related future tax assets and a compensation expense recovery of $0.6 million . No accounting recognition will be made until such time and to the extent that proposed changes to the deductibility of stock option payments for tax purposes has been substantively enacted.
Critical Accounting Estimates
There have been no material changes to critical accounting estimates since December 31, 2009. 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
There have been no changes to accounting policies since December 31, 2009.
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.
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Project Structure and Governance
A Steering Committee has been established to provide leadership and guidance to the project team, assist in developing accounting policy recommendations and ensure there is adequate resources and training available. Management provides status updates to the Audit Committee on a quarterly basis.
Resources and Training
CE Franklin’s project team has been assembled and has developed a detailed work plan that includes training, detailed Canadian GAAP to IFRS analysis, technical research, policy recommendations and implementation. The project team completed initial training and ongoing training will continue through the project as required. The Company’s Leadership Team and the Audit Committee have also participated in IFRS awareness sessions.
IFRS Progress
The project team is advanced in its assessment of the differences between Canadian GAAP and IFRS. A risk based approach was used to identify significant differences based on possible financial impact and complexity. No accounting policy differences have been identified to date that would give rise to significant differences between Canadian GAAP and IFRS except in stock based compensation where the assessment work continues. Similarly, there have been no significant information system change requirements identified in order to adopt IFRS. The project team has substantially completed its assessment of changes to financial statement presentation, disclosure and again no significant differences have been identified to this point. There are some additional disclosures required under IFRS that the company will be presenting in its first IFRS financial statements. Work is ongoing on internal controls over f inancial reporting that will be required to adopt IFRS. There are a number of IFRS standards in the process of being amended by the International Accounting Standards Board and are expected to continue until the transition date of January 1, 2011. The Company is actively monitoring proposed changes.
At this stage in the project, CE Franklin has determined that the impact of adopting IFRS will be minimal to its financial position and future results.
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 Canadian GAAP 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, 2010 that have materially affected or are reasonably likely to materially affect the ICFR. No such changes were identified through their evaluation.
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 year ended December 31, 2009 have occurred that would materially change the 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 Factor s”.
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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 2010 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 second quarter 2010 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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