CALGARY, ALBERTA — (Marketwire) — 03/13/13 — GASFRAC (TSX: GFS) announced fourth quarter 2012 revenues of $46.9 million resulting in EBITDA of $7.7 million, including $1.9 million of insurance proceeds. Sequentially this represented an increase from $40.9 million of revenue and $1.0 million of EBITDA in the third quarter of 2012. In the fourth quarter of 2011 EBITDA was $7.9 million on revenues of $59.3 million.
James Hill, Chief Financial Officer commented “I am proud of what our team accomplished during the fourth quarter. The impact of decisions made late in the third quarter are reflected in our fourth quarter results. Sequentially we have achieved a reduction in fixed costs of more than $3.5 million in the quarter and are on track to driving our breakeven quarterly revenue to $30 million from its $40 million level in the third quarter. With a more sustainable cost structure in place we are focused on expanding our customer and revenue base through targeted selling driven by providing customer solutions and value. In particular, the augmentation of our service portfolio to include hybrid delivery and tailored high reid vapour pressure fluids expands our market and enhances value for our customers.
Late in the quarter we completed our first hybrid frac and performed the second in early February. These jobs were very successful and augment the Company–s service delivery with a premium process allowing us to pump up to 300 tonnes of proppant per day. We will continue to refine this hybrid process to further expand our daily tonnage delivery. In addition we now have added the ability to tailor our frac fluid for specific suitability to the customer–s formation allowing for the use of local fluid sources and recovery of the fluid through flowback into pressure tanks or into the gathering system. Both of these initiatives reduce total service cost for our customers and enhance our seamless delivery of service (frac to production).
I am also pleased to announce that GASFRAC was awarded the Leading Technologies Award – Commercial Application at the Platts 2012 Global Energy Awards.”
Pursuant to our operations review initiated in the third quarter, we have parked five sets of equipment and during the fourth quarter we have recorded an impairment to those assets of $45 million.
Two of the Company–s key patents (Liquified Petroleum Gas Fracturing System – Gas Blanket and Proppant Addition System and Method) have now been issued/allowed in the USA. These patents cover the key intellectual property surrounding the process of safely fracturing using LPG.
The board of directors special committee has conducted a search for a CEO over the last several months, utilizing an executive search firm. A number of potential candidates have been identified and interviewed and the board plans to make a decision within the next 60 days.
MANAGEMENT–S DISCUSSION AND ANALYSIS
DECEMBER 31, 2012
Management–s discussion and analysis (“MD&A”) of the financial condition and the results of operations should be read in conjunction with the consolidated financial statements for the year ended December 31, 2012 of GASFRAC Energy Services Inc. (“GASFRAC” or the “Company”), together with the accompanying notes. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
Readers should also refer to the “Forward-Looking Statements” legal advisory at the end of this MD&A. This MD&A has been prepared using information that is current March 13, 2013.
All references to dollar amounts are in Canadian dollars. Figures are in –000s except share and per share data or as otherwise noted.
Unless the context otherwise requires, all references in this MD&A to “we”, “us” or “our” mean the Company.
BUSINESS OF GASFRAC
GASFRAC Energy Services Inc. was incorporated on February 13, 2006 in Canada under the Business Corporations Act in the Province of Alberta. The Company is an oil and gas well fracturing company that has developed new technology, the “LPG Fracturing Process”, to enable wells to be fractured safely with LPG, more specifically propane and butane. The Company operates in Canada and the United States through six wholly-owned subsidiaries, the GASFRAC Energy Services GP Inc., GASFRAC Energy Services Limited Partnership, GASFRAC Luxembourg Finance (a Luxembourg incorporated entity), GASFRAC Energy Services (US) Inc. (a U.S. incorporated entity), GASFRAC US Holdings Inc., and GASFRAC Inc. (a U.S. incorporated entity).
COMPARATIVE ANNUAL FINANCIAL INFORMATION
(1) Defined under Non-IFRS Measures
OPERATIONAL REVIEW
Late in the third quarter, the Board of Directors announced management changes and an operational review. As of the date of this report, the board of directors is continuing a formal search for a new chief executive officer. The board is also considering augmenting its current board composition with additional experience and expertise as GASFRAC continues to grow.
The operational review assessed our infrastructure and ensured that it was being appropriately deployed to support operational efficiency, while ensuring long-term profitability, sustainably and the continued growth of GASFRAC–s proprietary technology.
As a result of the operational review, we determined that it was prudent to refocus our operations on near-term growth opportunities in North America where we have demonstrated particular success. Specifically, in Canada we are targeting areas in the western Canada sedimentary basin. In the U.S., we are focusing on areas in South Texas and Colorado. To help support this initiative, we have established core sales and engineering teams in these regions that are focused on serving and growing our client base. By focusing on these areas we were able to reduce our overall U.S. field and support staff by 25% to a level to support two sets of equipment. Likewise, Canadian staffing levels were reduced by 20% to a level to support three sets of equipment. Additional changes have been made to reduce charges associated with facilities, staff housing, insurance and other fixed costs.
The impact of these reductions was realized during the fourth quarter with quarterly fixed costs being reduced sequentially by approximately $3.8 million and the resultant quarterly cash breakeven revenue being reduced to approximately $30 million from an estimated $39 million. Revenues for the quarter of $46.9 million resulted in EBITDA of $7.7 million. This compares to third quarter revenue of $40.9 million with an EBITDA of $1.0 million.
Operationally, the Company successfully completed its first hybrid fracturing treatment in South Texas. This new delivery system allows the Company to increase the daily tonnage of proppant pumped beyond the 100 tonne standard with our conventional system, opening the market opportunity for larger horizontal fracturing treatments being used in formations such as the Eagle Ford.
FINANCIAL OVERVIEW – FOR THE THREE MONTHS ENDED
REVENUE
Revenue for the fourth quarter decreased 20.9% to $46.9 million from $59.3 million in the fourth quarter of 2011.
During the quarter, the company earned revenues from 11 customers with the top three customers representing 70.8% of the total revenue. During the fourth quarter of 2011, the top three customers represented 54.2% of the total revenue.
Canadian operations:
Fourth quarter revenue from the Canadian operations decreased 7.2% to $33.7 million from $36.3 million in the fourth quarter of 2011. The reduction reflects fewer smaller oil companies utilizing the Company–s services due to capital constraints. This was offset by improved revenues from the Company–s core customers. The Canadian operations performed 79 operating days in the fourth quarter of 2012 with an average daily revenue of $425 compared to 54 operating days in the fourth quarter of 2011 with an average daily revenue of $672. The decrease in average daily revenue is due to the decrease in the price and cost of LPG as well as an increase in the amount of customers that supplied their own proppant.
During the quarter, revenue was generated from 7 customers with the top 3 customers representing 86.6% of the total revenue. During the fourth quarter of 2011, the top 3 customers represented 70.5% of the total revenue.
U.S. operations:
Fourth quarter revenue from the U.S. operations decreased 42.6% to $13.2 million from $23.0 million in the fourth quarter of 2011. While our core US client was active in October, hunting season restrictions prevented operations during November and most of December. They recommenced operations on these lands in February with the Company–s second hybrid fracturing treatment. U.S. operations produced 27 operating days in the fourth quarter of 2012 with an average daily revenue of $490 compared to 43 revenue days in the fourth quarter of 2011 with an average daily revenue of $535. The decrease in average daily revenue is mainly due to the decrease in price and cost of LPG. In the fourth quarter of 2011, the Company was engaged by two customers to perform pilot projects in the Niobarra.
During the quarter, revenue was generated from 4 customers with the top 3 customers representing 96.4% of the total revenue. During the fourth quarter of 2011, the top three customers represented 95.6% of the total revenue.
OPERATING EXPENSES
Operating expenses (comprised of cost of sales and direct operating costs) decreased 20.9% to $35.3 million from $44.6 million in the fourth quarter of 2011. Cost of sales was $24.4 million (51.9%) as compared to $34.3 million (57.8%) in the fourth quarter of 2011. Direct operating costs were $11.0 million as compared to $10.3 million in the fourth quarter of 2011. Direct operating costs were comprised of fixed costs of $7.1 million and variable costs of $3.9 million as compared to fixed costs of $6.0 million and variable costs of $4.3 million in the fourth quarter of 2011 and fixed costs of $8.2 million and variable costs of $5.0 million in the third quarter of 2012.
Canadian operations:
During the fourth quarter, operating expenses decreased 13.5% to $24.3 million from $28.1 million in the fourth quarter of 2011. Cost of sales decreased to $17.3 million (51.3%) from $20.3 million (56.0%). Direct operating costs were $7.1 million as compared to $7.7 million in the fourth quarter of 2011 and $7.9 million in the third quarter of 2012. These were comprised of $4.3 million of fixed costs and $2.8 million (8.3%) of variable costs as compared to fixed costs of $4.3 million and variable costs of $3.4 million (9.5%) in the fourth quarter of 2011 and fixed costs of $4.9 million and variable costs of $3.0 million (11.2%) in the third quarter of 2012.
U.S. operations:
During the fourth quarter, operating expenses were $11.0 million compared to $16.5 million in the fourth quarter of 2011. Cost of sales decreased to $7.0 million (53.6%) from $13.9 million (60.7%). Direct operating costs were $3.9 million as compared to $2.5 million in the fourth quarter of 2011 and $5.3 million in the third quarter of 2012. These were comprised of $2.9 million of fixed costs and $1.0 million (7.6%) of variable costs as compared to fixed costs of $1.6 million and variable costs of $0.9 million (7.5%) in the fourth quarter of 2011 and fixed costs of $3.3 million and variable costs of $2.0 (14%) million in the third quarter of 2012.
IMPAIRMENT OF U.S. BASED ASSETS
The Company has determined that there is an impairment in the value of the assets of the U.S. cash generating unit. In assessing the potential impairment of assets, the Company considered both the fair value less costs to sell and the value in use. In making its assessment, consideration was given to the Company–s current market position in the U.S. and to the overall pressure pumping market in the U.S. which is currently experiencing an over-supply of equipment which we do not expect to reverse during 2013. Management–s forecast of expected cash flows does not support the four sets of equipment allocated to the region. Management has therefore concluded that while this oversupply is experienced, an impairment in the carrying value of the U.S. assets exists in an amount of approximately $24.8 million and has been recognized in these financial statements. The impairment of $24.8 million is based on management–s estimate of the fair value less cost to sell as determined based on estimates of the amounts that could be obtained in a non-compulsory asset sale, with an arm–s length willing third party.
IMPAIRMENT OF CANADIAN BASED ASSETS
The Company has determined that there is an impairment in the value of the assets of the Canadian cash generating unit. In assessing the potential impairment of assets, the Company considered both the fair value less costs to sell and the value in use. In making its assessment, consideration was given to the Company–s current market position in Canada and to the overall pressure pumping market in the Canada which is currently experiencing an over-supply of equipment which we do not expect to reverse during 2013. Management–s forecast of expected cash flows does not support the five sets of equipment allocated to the region. Management has therefore concluded that while this oversupply is experienced, an impairment in the carrying value of the Canadian assets exists in an amount of approximately $20.0 million and has been recognized in these financial statements. The impairment of $20.0 million is based on management–s estimate of the fair value less cost to sell. Fair value was derived using an earnings multiple approach, in which an implied multiple was applied to the CGU–s forecasted EBITDA. The implied multiple was based on a review of comparable company trading multiples. Additional consideration was given for the value that could be obtained for redundant equipment in a non-compulsory asset sale, with an arm–s length willing third party.
SALES, GENERAL & ADMINISTRATIVE (“SG&A”) EXPENSES
For the fourth quarter, SG&A expenses decreased 1.8% to $5.5 million from $5.6 million in the fourth quarter of 2011. The decrease is primarily due to decreased salaries and benefits associated with the reductions of the executive and administrative staffing levels that occurred in the third quarter of 2012.
EBITDA
For the fourth quarter, EBITDA decreased to $7.7 million as compared to $7.9 million in the fourth quarter of 2011 and $1.1 million in the third quarter of 2012. The increase from the third quarter of 2012 is due to the decrease in fixed direct operating costs as a result of the restructuring that occurred in September 2012.
NET LOSS
For the fourth quarter of 2012, the net loss was $48.5 million compared to a net income of $1.5 million during the fourth quarter of 2011. The creation of the net loss is primarily due to the impairment of the assets in the Canadian and U.S. cash generating units as well as an increase in depreciation due to the deployment of additional frac equipment.
FINANCIAL OVERVIEW – FOR THE TWELVE MONTHS ENDED
REVENUE
Revenue decreased 7.4% to $149.4 million from $161.4 million in 2011. 2011 revenue included a $20.9 million sale of materials to a customer. Adjusting for this one time sale, revenues from services increased 6.3% in 2012 as compared to 2011. Revenue per operating day decreased to $466 from $499 in 2011.
The Company earned revenues from 32 customers with the top three customers accounting for 67.4% of the Company–s revenue. During 2011, the top 3 customers accounted for 42.5% of the Company–s revenue.
Canadian operations:
Canadian operations generated $107.8 million of revenue from 227 operating days with an average daily revenue of $475. In 2011, Canadian operations generated $103.0 million of service revenue and $20.9 million of revenue from a product sale for total revenue of $123.9 million from 201 operating days at an average daily revenue of $513.
Revenue was earned from 14 customers during the year with three of these customers representing 79% of the total revenue. During 2011, the top 3 customers from the Canadian operations accounted for 49.5% of the Company–s Canadian revenue.
U.S. operations:
U.S. operations generated $41.6 million of revenue from 94 operating days at an average revenue per operating day of $443. In 2011, the U.S. operations generated $37.4 million of revenue from 81 operating days at an average daily revenue of $462.
Revenue was earned from 18 customers during the year with three of these customers representing 69% of the total revenue earned from U.S. operations. During 2011, the top 3 customers from the US operations accounted for 75.6% of the Company–s US revenue.
OPERATING EXPENSES
Operating expenses (comprises of cost of sales and direct operating costs) decreased to $127.7 million compared to $127.8 million in 2011. Cost of sales was $79.6 million (53.2% of revenue) as compared to $93.6 million (58.1% of revenue) in 2011. Direct operating costs increased to $48.1 million in 2012 as compared to $34.3 million in 2011. Direct operating costs were comprised of fixed costs of $28.0 million and variable costs of $20.1 million as compared to fixed costs of $19.9 million and variable costs of $14.4 million in 2011. The increase in fixed costs was primarily due to an increased in the headcount of field personnel.
Canadian operations:
Operating expenses from the Canadian operations were $85.6 million compared to the $99.2 million incurred in 2011. Cost of sales was $54.3 million (50.4% of revenue) as compared to $72.4 million (58.4% of revenue) in 2011. Direct operating costs increased to $31.4 million as compared to $26.8 million in 2011. Direct operating costs were comprised of fixed costs of $17.4 million and variable costs of $14.0 million (13.0%) as compared to fixed costs of $14.2 million and variable costs of $12.6 million (10.2%) in 2011.
U.S. operations:
Operating expenses from the U.S. operations was $42.0 million, compared to the $28.6 million incurred in 2011. Cost of sales was $25.3 million (60.7% of revenue) as compared to $21.2 million (56.5%) of revenue in 2011. Direct operating costs increased to $16.8 million in 2012 as compared to $7.5 million in 2011. Direct operating costs were comprised of fixed costs of $10.7 million and variable costs of $6.1 million (14.7%) as compared to fixed costs of $5.7 million and variable costs of $1.8 million (4.8%) in 2011. The increase in direct operating costs was the result of the increased operational staff.
SALES, GENERAL & ADMINISTRATIVE (“SG&A”) EXPENSES
SG&A expenses were $22.5 million compared $17.4 million in 2011. The increase over 2011 is primarily due an increase in executive and administrative that occurred in the first half of 2012 with subsequent severance costs of approximately $0.9 million accrued upon termination of executive and overhead staff in September 2012.
EBITDA
EBITDA was $0.6 million compared to $13.4 million in 2011. The decrease is primarily due to the increase in SG&A and fixed direct operating costs.
NET LOSS
Net loss was $77.5 million as compared to a $2.9 million net loss during 2011. The creation of the net loss is primarily due to the impairment of the assets in the Canadian and U.S. cash generating units in Q4 2012. The Company–s effective tax rate was 3.25% (2011 – 6.24%) compared to the statutory rate of 25.00% (2011 – 26.55%). The difference in effective tax rate as compared to the statutory tax rate results largely from certain tax losses not being recognized for accounting purposes at this time.
FINANCIAL OVERVIEW – SUMMARY OF QUARTERLY RESULTS
(1) Defined under Non-IFRS Measures
(2) Working capital is defined as current assets less current liabilities
LIQUIDITY AND CAPITAL RESOURCES
As at December 31, 2012, the Company had approximately $2.5 million of capital commitments as part of the 2012 capital program. The Company anticipates being able to fund these capital expenditures through cash on hand, operating cash flows and debt facilities.
OPERATING
Net cash generated from operating activities was $19.0 million as compared to a $9.6 million cash draw in 2011. During the year trade and other receivables of $15.2 million were collected that contributed substantially to the cash flow from operating activities.
FINANCING
Net cash provided by financing activities was $46.3 million compared to $29.0 million in 2011. The financing activities in 2012 consisted mainly from the issuance of convertible debentures ($37.9 million) and from the credit facility ($7.8 million).
The Company has a $10 million operating demand revolving loan facility and a $90 million committed revolving facility. In 2012, the bank syndicate approved amendments to the credit facility suspending the financial covenants relating to trailing twelve month EBITDA through to the end of Q1 2013 and limiting draws on the credit facility during this period to $60 million. As at December 31, 2012, the Company is in compliance with the covenants including the modified EBITDA covenant.
INVESTING
The Company invested $49.1 million in property and equipment and intangible assets for 2012 to add revenue producing capacity as compared to $125.7 million in 2011. The timing of cash outflows relating to financial liabilities are outlined in the following table:
To meet these financial obligations, The Company had available the following resources available within 1 year:
During 2012 the Company incurred a significant EBITDA loss in the second quarter and had large capital expenditure commitments for the completion of its 2011 capital program. To fund these costs, the Company issued a convertible debenture and drew on its bank line of credit. The EBITDA loss in the second quarter negatively impacted trailing twelve month EBITDA amounts used in the calculation of certain of the financial covenants under its credit facility. Accordingly, the Company reached an agreement with its bankers to suspend these covenants until the measuring date for the second quarter of 2013. Additionally, the Company implemented reductions to its operating costs in September 2012 through staff reductions, facility consolidation and the parking of certain equipment. The Company also renegotiated commitments for the purchase of raw materials for operations reducing 2013 commitments to $14.1 million from $58.1 million. Capital expenditure commitments for 2013 are $2.5 million. As a result of these actions the Company anticipates that operating cash flow and its bank credit facility will be sufficient to fund ongoing operations.
While there exists uncertainty as to the Company–s ability to meet all financial covenants for the all quarters during 2013, due to the limited amount drawn on the credit facility and the level of asset security, management does not anticipate that financing would be withdrawn. The bank credit facility matures August 31, 2013 and should it not be renewed is subject to repayment in seven quarterly repayments equal to 1/12 of the outstanding amount commencing in the second quarter following maturity with the remainder, including accrued interest, due with an eight payment two years following the maturity date. While the Company does not anticipate the credit facility not being renewed or called, in the event it is not, funding options would include a renegotiated bank credit line, equipment based funding supported by the Company–s asset base or term debt.
IMPAIRMENT OF U.S. PLANT AND EQUIPMENT
The Company has determined that there is an impairment in the value of the assets of the USA cash generating unit. In assessing the potential impairment of assets, the Company considered both the fair value less costs to sell and the value in use. In making its assessment, consideration was given to the Company–s current market position in the USA and to the overall pressure pumping market in the U.S. which is currently experiencing an over-supply of equipment which we do not expect to reverse during 2013. Management–s forecast of expected cash flows does not support the four sets of equipment allocated to the region. Management has therefore concluded that while this oversupply is experienced, an impairment in the carrying value of the USA assets exists in an amount of approximately $24.8 million and has been recognized in these financial statements. The impairment of $24.8 million is based on management–s estimate of the amounts that could be obtained in a non-compulsory asset sale, with an arm–s length willing third party.
IMPAIRMENT OF CANADIAN BASED ASSETS
The Company has determined that there is an impairment in the value of the assets of the Canadian cash generating unit. In assessing the potential impairment of assets, the Company considered both the fair value less costs to sell and the value in use. In making its assessment, consideration was given to the Company–s current market position in Canada and to the overall pressure pumping market in the Canada which is currently experiencing an over-supply of equipment which we do not expect to reverse during 2013. Management–s forecast of expected cash flows does not support the five sets of equipment allocated to the region. Management has therefore concluded that while this oversupply is experienced, an impairment in the carrying value of the Canadian assets exists in an amount of approximately $20.0 million and has been recognized in these financial statements. The impairment of $20.0 million is based on management–s estimate of the fair value less cost to sell. Fair value was derived using an earnings multiple approach, in which an implied multiple was applied to the CGU–s forecasted EBITDA. The implied multiple was based on a review of comparable company trading multiples. Additional consideration was given for the value that could be obtained for redundant equipment in a non-compulsory asset sale, with an arm–s length willing third party.
ACCOUNTING POLICIES AND ESTIMATES
This MD&A is based on the Company–s annual consolidated financial statements that have been prepared in accordance with IFRS. Management is required to make assumptions, judgments and estimates in the application of IFRS. The Company–s summary of significant accounting policies are described in Note 2 of the December 31, 2012 audited consolidated financial statements. The preparation of the consolidated financial statements requires that certain estimates and judgments be made concerning the reported amount of revenue and expenses and the carrying values of assets and liabilities. These estimates are based on historical experience and management–s judgment. Anticipating future events involves uncertainty and, consequently, the estimates used by management in the preparation of the consolidated financial statements may change as future events unfold, additional experience is acquired or the environment in which the Company operates changes.
Apart from the key source of estimation uncertainty disclosed below, all key assumptions concerning the future, and other key sources of estimation uncertainty made at the end of the last full reporting period were applied consistently for the twelve months ended December 31, 2012.
Valuation of debenture holders– conversion option
In order to value the debenture holders– conversion option, management had to determine what interest rate a similar debt instrument will carry if it had no conversion privilege. Management reviewed similar issues within the Canadian debt market of unrated entities and concluded that such a similar debt instrument without conversion privilege will carry a 10% coupon interest rate.
Also, the Company–s option to redeem the debentures before maturity is considered closely related to the host debt instrument and thus not separately valued.
Useful lives of plant and equipment
The Company reviews the estimated useful lives of plant and equipment at the end of each reporting period. These estimates may change as more experience is obtained or as general market conditions change, thereby impacting the operation of the Company–s property and equipment. Amortization of the finite intangible assets also incorporates estimates of useful lives and residual values. During the current year, no changes were made to the economic useful life plant and equipment.
Recognition of deferred tax assets
The Company only recognizes a deferred tax asset when it is probable that taxable benefits would be received in the future. The probability of future taxable benefits is based upon the earnings history of the Company, management–s best estimate of future earnings and expectations of future tax rates based on legislation in place in the relevant jurisdiction.
Share based compensation estimates
The Company calculates the fair value of its options using the Black-Scholes option pricing model. Based on available information the Company estimates the fair value using the following weighted average assumptions to determine the fair value of the options at the date of grant. All share options are granted at the market value of the shares on grant date.
Performance share unit grants are linked to corporate performance and grants vest from one to three years from date of grant. The Company periodically assesses expectations as to the performance achieved as an input variable to the calculation of its liability pursuant to performance share units.
Recoverability of accounts receivable
The Company performs ongoing credit evaluations of its customers and grants credit based upon a credit review and review of historical collection experience, current aging status, financial condition of the customer and anticipated industry conditions. Customer payments are regularly monitored and an allowance for doubtful accounts is established based upon specific situations and overall industry conditions affecting individual. The Company–s management believes that the allowance for doubtful accounts is adequate.
Impairment evaluation of plant and equipment and intangible assets
The Company evaluates the plant and equipment and intangible assets for possible impairment when impairment indicators exist. The Company allocated plant and equipment and intangible assets into cash generating units (CGU) based on the geographical area within which the assets operate. The impairment is determined based of the highest of the value in use or fair value less cost to sell of each CGU.
The value in use is based on the medium term budget, management estimates the future net cash flow expected to be generated by each CGU and determines the present value of these future cash flows by applying a weighted cost of capital that represents management–s estimate of the return expected by each capital provider. Key assumptions in the calculation of future cash flows include; the number of fracturing sets operating, utilization rates for each set and the discount rate used for determination of net present value. The fair value is derived from an earnings before interest, taxes, depreciation and amortization (EBITDA) multiple with additional consideration of the value that could be obtained for redundant equipment in a non-compulsory asset sale with an arm–s length third party. The EBITDA multiple is determined by looking at multiples of comparable public companies. EBITDA figures are based off normalized historical results of each CGU and adjusted for forecasted assumptions including expected utilization rates and headcount.
When assets that do not fall within a CGU have to be considered for impairment, management estimates the recoverable amount for each asset based upon current market value of such an asset between arm–s length parties.
These assumptions and estimates are uncertain and are subject to change as new information becomes available. Changes in economic conditions can also affect the discount rate or EBITDA multiple.
RELATED PARTY TRANSACTIONS
Details of transactions between the Company and other related parties are disclosed below
Trading transactions:
During the year, the Company entered into the following trading transactions with related parties that are not members of the Company:
The following balances were outstanding at the end of the reporting period:
Sales of goods to related parties were made at the Company–s usual list prices. The amounts outstanding are unsecured and will be settled in cash. No guarantees have been given or received. No expense has been recognized in the current or prior years for bad or doubtful debts in respect of the amounts owed by related parties
During the year, the Company also paid $nil (2011 – $62 thousand) in consulting fees to certain Directors. These transactions were in the normal course of operations and have been measured at the exchange amounts.
OUTSTANDING SHARE DATA
FINANCIAL INSTRUMENTS
The Company–s strategy is to maintain a capital structure to sustain future growth of the business and retain creditor, investor and market confidence. Recognizing the cyclical nature of the oilfield services industry, the Company strives to maintain a conservative balance between long-term debt and shareholders– equity. The Company–s capital structure is currently comprised of shareholders– equity and undrawn long-term bank debt. The Company may occasionally need to increase its level of long-term debt to total capitalization to facilitate growth activities.
The company has a $10 million operating demand revolving loan facility and a $90 million committed revolving facility, both of which are subject to various financial and non financial covenants. The covenants are monitored on a regular basis and controls are in place to ensure the Company maintains compliance with these covenants. As at December 31, 2011, the Company is in compliance with all the covenants related with this facility.
The Company monitors its capital structure and makes adjustments in light of changing market conditions and new opportunities, while remaining cognizant of the cyclical nature of the oilfield services sector. To maintain or adjust its capital structure, the Company may revise its capital spending, issue new shares, issue new debt, or draw on its current operating line facility.
Financial risk management objectives
The Company monitors and manages the financial risks relating to the operations of the Company through internal risk procedures which analyze exposures by degree and magnitude of risks. These risks include market risk (including currency risk, interest rate risk and other price risk), credit risk and liquidity risk.
Currently, the Company does not use derivative financial instruments to manage any financial risks. Exchange rate risk managed through foreign currency denominated invoicing by The Company–s US subsidiary and reducing the timing of between procurement and payment of foreign currency denominated payables.
Market risk
Foreign currency exchange rate risk
As the Company operates primarily in Canada and the United States of America (“U.S.”), fluctuations in the exchange rate between the U.S. dollar and Canadian dollar can have a significant effect on the operating results and the fair value or future cash flows of The Company–s financial assets and liabilities. The Canadian entities are exposed to currency risk on foreign currency denominated financial assets and liabilities with adjustments recognized as foreign exchange gains or losses in the consolidated statement of comprehensive income. The U.S. entities with a U.S. dollar denominated functional currency expose the Company to currency risk on the translation of these entities– financial assets and liabilities to Canadian dollars on consolidation. In addition, U.S. entities are exposed to currency risk on financial assets and liabilities denominated in currencies other than their functional currency (U.S. dollars) with adjustments recognized in the consolidated statements of comprehensive income. For the year ended December 31, 2012, a 1% fluctuation in the value of the Canadian dollar relative to the U.S. dollar would have impacted profit before tax by $nil (2011 – $19 thousand.
Interest rate risk
The Company is exposed to interest rate risk because the Company borrows funds at only variable interest rates. The sensitivity analyses have been determined based on the exposure to interest rates for applicable to outstanding borrowings at the end of the reporting period. For floating rate liabilities, the analysis is prepared assuming the amount of the liability outstanding at the end of the reporting period was outstanding for the whole year. A 50 basis point increase or decrease is used when reporting interest rate risk internally to key management personnel and represents management–s assessment of the reasonably possible change in interest rates. If interest rates had been 50 basis points higher/lower and all other variables were held constant, The Company–s profit before tax would be $46 thousand lower/higher based on the borrowings outstanding at year end. (2011 – $111 thousand). All finance leases are concluded at fixed interest rates and a change in market interest rates relating to finance leases will not impact the Company–s profit. The Company–s sensitivity to interest rates has increased during the current year mainly due to the continued capital construction program leading to a draw on The Company–s credit facility.
Credit risk
Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Company. The Company assesses the creditworthiness of its customers on an ongoing basis. The Company–s exposure and the credit ratings of its counterparties are continuously monitored as are amounts outstanding and age of receivables.
Trade receivables are predominately with customers who explore and develop petroleum and natural gas resources mainly in Canada and the southern U.S. The Company is subject to normal industry credit risk. This includes fluctuations in oil and natural gas commodity prices and the ability of customers to obtain attractive debt and/or equity financing. These balances represent the Companies total credit exposure. During the year, the Company earned revenues from more than 40 (2011: greater than 50) customers with the top three customers representing 67% (2011 – 42%) of revenue.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company has adequate credit facilities in place to meet its current commitments as they become due and further manages its liquidity risk by continuously monitoring forecasts and actual cash flows.
Fair values of financial instruments
The fair value of The Company–s financial instruments included on the consolidated balance sheet approximate their carrying amounts due to their short term maturity.
BUSINESS RISK
The business of the Company is subject to certain risks and uncertainties, including those listed below. Prior to making any investment decision regarding the Company, investors should carefully consider, among other things, the risk factors set forth below.
Volatility of Industry Conditions: The demand, pricing and terms for The Company–s fracturing and well stimulation services largely depend upon the level of exploration and development activity for North American oil and natural gas. Industry conditions are influenced by numerous factors over which the Company has no control, including the level of oil and natural gas prices, expectations about future oil and natural gas prices, the cost of exploring for, producing and delivering oil and natural gas, the decline rates for current production, the discovery rates of new oil and natural gas reserves, available pipeline and other oil and natural gas transportation capacity, weather conditions, political, military, regulatory and economic conditions, and the ability of oil and natural gas companies to raise equity capital or debt financing. A material decline in global oil and natural gas prices or North American activity levels as a result of any of the above factors could have a material adverse effect on The Company–s business, financial condition, results of operations and cash flows. Because of the current economic environment and related decrease in demand for energy, natural gas exploration and development in North America has decreased from peak levels in 2008. Warmer than normal winters in North America, among other factors, may adversely impact demand for natural gas and, therefore, demand for oilfield services. If the economic conditions deteriorate further or do not improve, the decline in natural gas exploration and development could cause a decline in the demand for The Company–s services. Such decline could have a material adverse effect on The Company–s business, financial condition, results of operations and cash flows.
Demand for Oil and Natural Gas: Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices could reduce the demand for crude oil and other hydrocarbons. The Company cannot predict the impact of changing demand for oil and natural gas products, and any major changes could have a material adverse effect on The Company–s business, financial condition, results of operations and cash flows.
Seasonality: The Company–s financial results are directly affected by the seasonal nature of the North American oil and natural gas industry. The first quarter incorporates the winter drilling season when a disproportionate amount of the activity takes place in western Canada. During the second quarter, soft ground conditions typically curtail oilfield activity in all of The Company–s Canadian operating areas such that many rigs are unable to move about due to road bans. This period, commonly referred to as “spring breakup”, occurs earlier in the year in southeastern Alberta than it does in northern Alberta and northeastern British Columbia. Consequently, this is The Company–s weakest three-month revenue period. Additionally, if an unseasonably warm winter prevents sufficient freezing, the Company may not be able to access well sites and The Company–s operating results and financial condition may therefore be adversely affected. The demand for fracturing and well stimulation services may also be affected by severe winter weather in North America. In addition, during excessively rainy periods in any of The Company–s operating areas, equipment moves may be delayed, thereby adversely affecting revenues. The volatility in the weather and temperature can therefore create unpredictability in activity and utilization rates, which can have a material adverse effect on The Company–s business, financial condition, results of operations and cash flows.
Concentration of Customer Base: The Company–s customer base consists of over thirty oil and natural gas exploration and production companies, ranging from large multinational public companies to small private companies. The Company had three significant customers that collectively accounted for approximately 72% of The Company–s revenue for the year ended December 31, 2012. One of these customers accounted for 43% of revenue. The Company–s strong relationships with exploration and production companies may result in increased concentration of revenues during periods of reduced activity levels such as the first three months of the year. However, there can be no assurance that the Company –s relationship with its primary customers will continue, and a significant reduction or total loss of the business from these customers, if not offset by sales to new or existing customers, would have a material adverse effect on the Company –s business, financial condition, results of operations and cash flows.
Competition: Each of the markets in which the Company participates is highly competitive. To be successful, a service provider must provide services that meet the specific needs of oil and natural gas exploration and production companies at competitive prices. The principal competitive factors in the markets in which the Company operates are product and service quality and availability, technical knowledge and experience, reputation for safety and price. The Company competes with large national and multinational oilfield service companies that have greater financial and other resources. These companies offer a wide range of well stimulation services in all geographic regions in which the Company operates. In addition, the Company competes with several regional competitors. As a result of competition, it may suffer from a significant reduction in revenue or be unable to pursue additional business opportunities.
Equipment Inventory Levels: Because of the long-life nature of oilfield service equipment and the lag between when a decision to build additional equipment is made and when the equipment is placed into service, the inventory of oilfield service equipment in the industry does not always correlate with the level of demand for service equipment. Periods of high demand often spur increased capital expenditures on equipment, and those capital expenditures may add capacity that exceeds actual demand. This capital overbuild could cause The Company–s competitors to lower their rates and could lead to a decrease in rates in the oilfield services industry generally, which could have a material adverse effect on the Company –s business, financial condition, results of operations and cash flows.
Sources, Pricing and Availability of Raw Materials and Component Parts: The Company sources its raw materials, such as proppant, chemicals, nitrogen, carbon dioxide and diesel fuel, and component parts, from a variety of suppliers in North America. Should The Company–s suppliers be unable to provide the necessary raw materials and component parts at an acceptable price or otherwise fail to deliver products in the quantities required, any resulting delays in the provision of services could have a material adverse effect on The Company–s business, financial condition, results of operations and cash flows.
Capital-Intensive Industry: The Company–s business plan is subject to the availability of additional financing for future costs of operations or expansion that might not be available, or may not be available on favourable terms. The Company–s activities may also be financed partially or wholly with debt, which could increase The Company–s debt levels above industry standards. The level of The Company–s indebtedness from time to time could impair The Company–s ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise. If the Company –s cash flow from operations is not sufficient to fund the Company –s capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on favourable terms.
Patents and Proprietary Technology: The Company–s success will depend, in part, on its ability to obtain patents, maintain trade secret protection and operate without infringing on the rights of third parties. The LPG Fracturing Process patents for the U.S., Canada and International markets remain in examination. However, there can be no assurance that any issued patents will provide the Company with any competitive advantages or will not be successfully challenged by any third parties, or that the patents of others will not have an adverse effect on the ability of the Company to do business. In addition, there can be no assurance that others will not independently develop similar products, duplicate some or all of The Company–s products, or, if patents are issued to the Company, design their products so as to circumvent the patent protection that may be held by the Company. In addition, the Company could incur substantial costs in lawsuits in which the Company attempts to enforce its own patents against other parties.
Operational Risks: The Company–s operations are subject to hazards inherent in the oil and natural gas industry, such as equipment defects, malfunction and failures, and natural disasters which result in fires, vehicle accidents, explosions and uncontrollable flows of natural gas or well fluids that can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to or destruction of property, equipment and the environment. These hazards could expose the Company to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution, contamination of drinking water and other environmental damages. the Company continuously monitors its activities for quality control and safety, and although it maintains insurance coverage that it believes to be adequate and customary in the industry, such insurance may not be adequate to cover the Company –s liabilities and may not be available in the future at rates that the Company considers reasonable and commercially justifiable.
Availability of Qualified Staff: Attracting and retaining qualified workers is necessary for the Company to provide reliable services to its customers. With high industry activity there is also high demand for qualified workers and, as such, it is a challenge for the Company to add a significant number of workers to support its planned growth. The Company attempts to overcome this challenge by offering an attractive compensation package, providing an in-depth training program, and offering career growth opportunities.
Availability of Debt Financing: The Company has facilities with its bank for $100 million of debt financing. As discussed in Note 15 of the 2012 Consolidated Audited Financial Statements this amount is limited to $60 million during the period in which certain financial covenants have been suspended. During 2012 the Company incurred a significant EBITDA loss in the second quarter and had large capital expenditure commitments for the completion of its 2011 capital program. To fund these costs, the Company issued a convertible debenture and drew on its bank line of credit. The EBITDA loss in the second quarter negatively impacted trailing twelve month EBITDA amounts used in the calculation of certain of the financial covenants under its credit facility. Accordingly, the Company reached an agreement with its bankers to suspend these covenants until the measuring date for the second quarter of 2013. Additionally, the Company implemented reductions to its operating costs in September 2012 through staff reductions, facility consolidation and the parking of certain equipment. The Company also renegotiated commitments for the purchase of raw materials for operations reducing 2013 commitments to $14.1 million from $58.1 million. Capital expenditure commitments for 2013 are $2.5 million. As a result of these actions the Company anticipates that operating cash flow and its bank credit facility will be sufficient to fund ongoing operations. The bank credit facility matures August 31 and should it not be renewed is subject to repayment in seven quarterly repayments equal to one twelve of the outstanding amount commencing in the second quarter following maturity with the remainder due with an eight payment two years following the maturity date. Should the Company be unable to renew these facilities in the amount it requires or on terms acceptable to it, significant liquidity issues could result.
Financing of Future Growth: The Company–s future growth strategy is subject to the availability of financing to support the acquisition of additional capital equipment. This growth may be fully or partially financed with debt which may or may not be available at the time required. Should such debt financing not be available as required it could result in a delay in The Company–s ability to grow its operations. Should the Company obtain debt financing there are no assurances that debt levels may increase above industry standards due to the impact of seasonal or cyclical trends or other factors.
Management Stewardship: The successful operation of The Company–s business depends upon the abilities, expertise, judgment, discretion, integrity and good faith of The Company–s executive officers, employees and consultants. In addition, The Company–s ability to expand its services depends upon its ability to attract qualified personnel as needed. The demand for skilled oilfield employees is high, and the supply is limited. If the Company loses the services of one or more of its executive officers or key employees, it could have a material adverse effect on The Company–s business, financial condition, results of operations and cash flows.
Regulations Affecting the Oil and Natural Gas Industry: The operations of The Company–s customers are subject to or impacted by a wide array of regulations in the jurisdictions in which they operate. As a result of changes in regulations and laws relating to the oil and natural gas industry, The Company–s customers– operations could be disrupted or curtailed by governmental authorities. The high cost of compliance with applicable regulations could cause customers to discontinue or limit their operations and may discourage companies from continuing development activities. As a result, demand for The Company–s services could be substantially affected by regulations adversely impacting the oil and natural gas industry. Changes in environmental requirements may negatively impact demand for The Company–s services. For example, oil and natural gas exploration and production may decline as a result of environmental requirements (including land use policies responsive to environmental concerns). A decline in exploration and production, in turn, could materially and adversely affect the Company.
Government Regulations: The Company–s operations are subject to a variety of federal, provincial, state and local laws, regulations and guidelines in all the jurisdictions in which it operates, including laws and regulations relating to health and safety, the conduct of operations, taxation, the protection of the environment and the manufacture, management, transportation and disposal of certain materials used in The Company–s operations. The Company has invested financial and managerial resources to ensure such compliance and expects to continue to make such investments in the future. Such laws or regulations are subject to change and could result in material expenditures that could have a material adverse effect on The Company–s business, financial condition, results of operations and cash flows. It is impossible for the Company to predict the cost or impact of such laws and regulations on The Company–s future operations. In particular, the Company is subject to increasingly stringent laws and regulations relating to importation and use of hazardous materials, radioactive materials and explosives, environmental protection, including laws and regulations governing air emissions, water discharges and waste management. The Company incurs, and expects to continue to incur, capital and operating costs to comply with environmental laws and regulations. The technical requirements of these laws and regulations are becoming increasingly complex, stringent and expensive to implement. These laws may provide for “strict liability” for damages to natural resources or threats to public health and safety. Strict liability can render a party liable for damages without regard to negligence or fault on the part of the party. Some environmental laws provide for joint and several strict liabilities for remediation of spills and releases of hazardous substances.
The Company uses and generates hazardous substances and wastes in its operations. In addition, some of The Company–s current properties are, or have been, used for industrial purposes. Accordingly, the Company could become subject to potentially material liabilities relating to the investigation and cleanup of contaminated properties, and to claims alleging personal injury or property damage as the result of exposures to, or releases of, hazardous substances. In addition, stricter enforcement of existing laws and regulations, new laws and regulations, the discovery of previously unknown contamination or the imposition of new or increased requirements could require the Company to incur costs or become the basis of new or increased liabilities that could reduce The Company–s earnings and cash available for operations. The Company believes it is currently in substantial compliance with applicable environmental laws and regulations.
The Company is a provider of hydraulic fracturing services; a process that creates fractures extending from the well bore through the rock formation to enable natural gas or oil to move more easily through the rock pores to a production well. Bills pending in the United States House of Representatives and Senate have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process. This legislation, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays and increased operating costs. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse effect on the Company –s business, financial condition, results of operations and cash flows.
Customers: Customers are generally invoiced for our services in arrears. As a result, we are subject to our customers delaying or failing to pay invoices. Risk of payment delays or failure to pay is increased during periods of weak economic conditions due to potential reduction in cash flow and access to capital of our customers.
The Market Price of the Common Shares May Be Volatile: The trading price of securities of oilfield service companies is subject to substantial volatility. The volatility is often based on factors both related to and not related to the financial performance or prospectus of the companies involved. The market price of The Company–s Common Shares could be subject to significant fluctuations in response to our operating results, financial condition and other internal factors. Factors that could affect the market price that are not directly related to The Company–s performance include commodity prices and market perceptions of the attractiveness of particular industries for investment. The price at which the Common Shares will trade cannot be accurately predicted.
Dilution from Further Equity Issuances: If the Company issues additional equity securities to raise additional funding or as consideration for the acquisition of a company or assets, as the case may be, such transactions may substantially dilute the interests of the Company–s Shareholders and reduce the value of their respective investment.
Dividends: The Company has not paid dividends prior to the date hereof and there can be no assurance that GASFRAC will pay dividends in the future. Dividend payments are at the discretion of the Company–s board of directors. Dividends depend on the financial condition of the applicable entity and other factors.
Additional Funding Requirements: The Company may need additional financing in connection with the implementation of its business and strategic plans from time to time. However, there can be no assurance that the Company will be able to obtain the necessary financing in a timely manner or on acceptable terms, if at all. The implementation of the Company–s business and strategic plans from time to time will require a substantial amount of capital and the amounts available to the Company without seeking additional debt or equity financing may not be sufficient to fund such business and strategic plans. The Company may accordingly have further capital requirements to take advantage of further opportunities or acquisitions.
Direct and Indirect Exposure to Volatile Credit Markets The ability to make scheduled payments on or to refinance debt obligations depends on the Company–s financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain finance, business and other factors beyond its control. Continuing volatility in the credit markets may increase costs associated with debt instruments due to increased spreads over relevant interest rate benchmarks, or affect the ability of the Company, or third parties it seeks to do business with, to access those markets.
In addition, access to further financing for the Company or its customers remains uncertain. This condition could have an adverse effect on the industry in which the Company operates and its business, including future operating results. The Company–s customers may curtail their drilling and completion programs, which could result in a decrease in demand for the Company–s services and could increase downward pricing pressures. In addition, certain customers could become unable to pay suppliers, including the Company, in the event they are unable to access the capital markets to fund their business operations. Such risks, if realized, could have a material adverse effect on the Company–s business, financial condition, results of operations and cash flows.
Merger and acquisition activity may reduce the demand for the Company–s Services. Merger and acquisition activity in the oil and gas exploration and production sector may constrain demand for the Company–s services as customers focus on reorganizing the business prior to committing funds to exploration and development projects. Further, the acquiring company may have preferred supplier relationships with oilfield service providers other than the Company.
Market for Convertible Debentures: If an active or liquid market for the Debentures fails to develop or be sustained, the prices at which the Debentures trade may be adversely affected. Whether or not the Debentures will trade at lower prices depends on many factors, including the liquidity of the Debentures, prevailing interest rates and the markets for similar securities, the market price of the Common Shares, general economic conditions and the Company–s financial condition, historic financial performance and future prospects. Further, the holders of the Common Shares may suffer dilution if the Company decides to redeem outstanding Debentures for Common Shares or to repay outstanding principal amounts thereunder at maturity of the Debentures by issuing additional Common Shares.
Repayment of Convertible Debentures: The Debentures are subordinate to Senior Indebtedness of the Company and to Repayment of the Debentures: The Company may not be able to refinance the principal amount of the Debentures in order to repay the principal outstanding or may not have generated enough cash from operations to meet this obligation. The Company may, at its option, on not more than 60 days and not less than 40 days prior notice and subject to any required regulatory approvals, unless an Event of Default has occurred and is continuing, elect to satisfy its obligat