Ironhorse Oil & Gas - Announces 2008 Year End Results
Calgary, Alberta CANADA, March 18, 2009 /FSC/ - Ironhorse Oil & Gas Inc. (IOG - TSX Venture), ("Ironhorse" or the "Company") is pleased to report its financial and operating results for the year ended, December 31, 2008.
Several significant accomplishments were achieved during the year:
* Production for the year ended December 31, 2008 increased 61% to 1,079 boe per day as compared to 670 boe per day in 2007.
* Funds from operations for year ended December 31, 2008 increased year over year 127% from $3.5 to $8.0 million or $0.18 to $0.39 per diluted share.
* Increased our credit facility to $14.5 million.
* Completed common share private placements for gross proceeds of $4.1 million.
* Net debt decreased 15% year over year from $8 million to $6.8 million.
* Positive reserves additions of 2,109 Mboe resulting from the Shackleton 2007/2008 infill drilling and technical revisions which represents a 68% increase in total proved plus probable reserves, net of production, for the year ended December 31, 2008.
* Finding and development costs, including changes in future capital, were $11.75 per boe proved plus probable.
* Licensed two (0.4 net) Nisku wells in the Pembina area, resulting in a significant Nisku oil discovery in the first quarter of 2009, as outlined in our press release dated January 20, 2009.
* Operating expenses decreased 31% year over year to $2.29 from $3.32 per boe.
* Net income of $1.6 million in 2008 versus a loss of $0.8 in 2007.
* Drilled 30 (15 net) gas wells in the Shackleton area bringing the total number of producing wells to 68 (34 net) gas wells.
* Acquired a 50% working interest in four sections of land in NE British Columbia with respect to a new prospect area which has multi zone potential.
An overview of the 2008 financial and operating highlights is set forth below:
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HIGHLIGHTS 2008 2007 % CHANGE
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Thousands except per share amounts
Financial
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Revenue 17,965 9,033 99
Royalties (6,883) (3,410) 102
Funds from operations 8,001 3,529 127
Per share - diluted 0.39 0.18 122
Net income (loss) 1,586 (812)
Per share -diluted 0.08 (0.04)
Capital expenditures 10,566 12,406 (15)
Net debt 6,789 7,983 (15)
Weighted average shares outstanding,
diluted 20,352 20,034 2
Operations
Production
Gas - mcf/d 6,434 3,977 62
Oil & ngls - bbl/d 7 7 -
Total - boe/d 1,079 670 61
Boe/d per million shares outstanding 53 33 61
Average sales price
Gas - $/mcf 7.52 6.13 23
Oil & ngls - $/bbl 92.47 71.06 30
Boe - $/boe 45.45 36.95 23
Royalties- $/boe 17.42 13.95 25
Operating - $/boe 2.29 3.32 (31)
Field Netback - $/boe 25.74 19.68 31
General & administrative expenses - $/boe 3.44 3.64 (5)
Reserves
Proved - Mboe 2,171 1,905 14
Proved Plus Probable - Mboe 4,229 2,513 68
Net Present Value before tax @10%
Proved 34,663 25,869 34
Proved Plus Probable 48,684 32,091 52
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Highlights of our operations to date for this winter's drilling season include:
* Drilling and placing on production of 32 (16 net) gas wells in the Shackleton area bringing the total number of producing wells to 100 (50 net) gas wells.
* Drilling two (0.4 net) Nisku oil discoveries in the Pembina area. We expect these wells will be placed on production in the fourth quarter of 2009. These wells are initially expected to increase our net production by 150 boe per day and once we establish a pressure maintenance scheme they should increase our net production by 600 - 800 boe per day.
* Increasing our net production in early March to over 1,250 boe per day; average production for 2009 is estimated at 1,150 - 1,250 boe per day depending on decline rates at Shackleton and the timing for placing the new Nisku oil wells at Pembina on production.
Ironhorse is well positioned financially to continue increasing its reserves and production profile during these times of economic uncertainty and volatility through a combination of grass roots exploration and acquisitions. The Board of Directors has approved a $12 million capital expenditure program for 2009. In addition to the activities undertaken in the first quarter of 2009, Ironhorse will focus on fulfilling its remaining flow-through expenditure commitments estimated at $2.2 million and placing the Pembina oil wells on production.
For additional information about Ironhorse Oil & Gas Inc. please go to the Company's web site at www.ihorse.ca.
Respectfully submitted on behalf of the Board of Directors,
Larry J. Parks
President & Chief Executive Officer
MANAGEMENT'S DISCUSSION and ANALYSIS
ADVISORIES
This Management's discussion and analysis ("MD&A"), prepared effective March 16, 2009 should be read in conjunction with the Ironhorse Oil & Gas Inc. ("Ironhorse" or the "Company") audited financial statements for the years ended December 31, 2008 and December 31, 2007.
Basis of Presentation - The financial data presented has been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). The reporting and measurement currency in the financial statements and in this discussion and analysis is the Canadian dollar, unless otherwise stated.
Non-GAAP Measures - Ironhorse evaluates performance based on net income, funds from operations, funds from operations per share, net debt and field netback. Funds from operations, funds from operations per share, net debt and field netback are not measurements defined by GAAP, but are financial terms commonly used in the oil and gas industry.
Funds from Operations are labelled on the Statement of Cash Flows and may not be comparable to other companies. Ironhorse calculates funds from operations as cash flow from operating activities prior to changes in non-cash working capital, and per share amounts are determined using the same method and shares outstanding, which are used in the determination of net earnings per share. The Company considers it a key measure as it demonstrates the ability of the Company to generate the funds necessary to finance future capital investments.
Field Netback - Ironhorse also uses field netback as a key performance indicator. Field netback does not have a standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures by other companies. Field netback is determined by deducting royalties and operating expenses from petroleum and natural gas sales revenue. The Company considers field netback a key measure in assessing the efficiency of its oil and gas assets.
Net Debt - Ironhorse also uses net debt as a key performance indicator. Net debt is calculated as current liabilities less current assets.
Funds from operations and field netback are not intended to represent operating profits, nor should they be viewed as an alternative to other measures of financial performance calculated in accordance with GAAP.
Boe Conversion - Certain natural gas volumes have been converted to barrels of oil equivalent ("boe"), whereby six thousand cubic feet ("mcf") of natural gas is equal to one barrel ("bbl") of oil, unless otherwise stated. This conversion ratio is based on an energy equivalent conversion applicable at the burner tip and does not represent a value equivalency at the wellhead.
Forward-Looking Information - Certain information regarding Ironhorse set forth in this document, including management's assessment of the Company's future plans and operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. These forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond Ironhorse's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, the lack of or availability of qualified technical personnel or management, stock market volatility and ability to access capital from internal and external sources. Ironhorse's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what impact it would have on Ironhorse. Words such as "may", "will", "should", "could", "anticipate", "believe", "expect", "intend", "plan", "potential", "continue", and similar expressions have been used to identify these forward-looking statements. These statements reflect management's current beliefs and are based on information currently available to management.
Examples of forward-looking statements in this MD&A include, but are not limited to the following, each of which is subject to significant risks and uncertainties and is based on assumptions which may prove to be incorrect:
* The expectation that the two (0.4 net) Pembina oil wells will be placed on production in the fourth quarter of 2009. These wells are initially expected to increase our net production by 150 boe per day and once we establish a pressure maintenance scheme they should increase our net production by 600 - 800 boe per day. Regulatory and/or operational delays could negatively impact the timing and production increases from this project.
* The expectation that the Company has sufficient financial resources to undertake and complete its remaining 2009 priorities including: the tie in of the Pembina oil wells; the establishment of pressure maintenance scheme at Pembina and fulfilling its remaining flow through expenditure obligations. This is subject to the risk and uncertainty of the Company's $14.5 million credit facility renewing at substantially lower levels and funds from operations being lower than the budgeted. Projected oil and gas commodity prices and production rates could vary significantly from current estimates resulting in decreases in our credit facility and/or funds from operations.
Risk Factors
Additional risk factors can be found under "Risk Factors" in the Company's Annual Information Form, which can be found on www.sedar.com. Many risks are discussed below, but these risk factors should not be construed as exhaustive. There are numerous factors, both known and unknown, that could cause actual results or events to differ materially from forecast results.
Oil and natural gas operations involve many risks that even a combination of experience and knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Company's reserves will depend not only on the Company's ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that further commercial quantities of oil and natural gas will be discovered or acquired by the Company.
The Company's principal risks include finding and developing economic hydrocarbon reserves efficiently and being able to fund the capital program. The Corporation's need for capital is both short-term and long-term in nature. Short-term working capital will be required to finance accounts receivable, drilling deposits and other similar short-term assets, while the acquisition and development of oil and natural gas properties requires large amounts of long-term capital. The Company anticipates that future capital requirements will be funded through a combination of funds from operations, debt and/or equity financing. There is no assurance that debt and equity financing will be available on terms acceptable to the Company to meet its capital requirements. If any components of the Company's business plan are missing, the Company may not be able to execute the entire business plan.
Although the Company has no set policy concerning derivative financial instruments, the management of the Company may use derivative financial instruments to reduce corporate risk in certain situations.
Internal Controls over Financial Reporting
Recent changes in securities laws no longer require the CEO and CFO of TSX Venture Exchange listed companies such as Ironhorse to certify they have designed internal control over financial reporting, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. Instead, an optional form of certification has been made available to TSX Venture Exchange listed companies and has been used by Ironhorse's certifying officers for the December 31, 2008 annual filings. The new certification reflects what the Company considers to be a more appropriate level of CEO and CFO certification given the size and nature of the Company's operations. This certification requires that the certifying officers state:
i) they have reviewed the annual MD&A and financial statements;
ii) they have determined there is no untrue statement of a material fact, or any omission of material fact required to be stated which would make any statement not misleading in light of the circumstances under which it was made within the annual MD&A and financial statements;
iii) that based upon their knowledge, the annual filings, together with the other financial information included in the annual filings, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of the date and for the periods presented in the filings.
Business Strategy
The business plan of the Company is to create profitable per share value growth in the exploration for, and the development and production of, natural gas and crude oil in western Canada. Ironhorse pursues a growth strategy involving exploratory and development drilling augmented by strategic acquisitions of properties and companies where exploitation, development and exploration opportunities exist. The Company's current areas of focus are in the western Canada corridor trending from northeast British Columbia to southwest Saskatchewan.
Ironhorse's strategy involves acquiring crown, freehold and First Nation mineral rights where our management and technical team have expertise. We believe this creates a competitive advantage for the Company.
Fourth quarter 2008 overview
For the three months ended December 31, 2008, production averaged 921 boe per day, a 39% increase from the 664 boe per day in the corresponding period of 2007. Year over year production increases resulted from the 2007/2008 drilling program at Shackleton, Saskatchewan. Production peaked in the second quarter of 2008 at an average rate of 1,143 boe per day and decreased through out 2008 due to normal declines.
Higher production and gas prices during the quarter ended December 31, 2008 resulted in funds from operations of $1.5 million versus $0.7 million in fourth quarter of 2007. Ironhorse closed a private placement in October 2008 for gross proceeds of $3.5 million. During the fourth quarter the Company incurred capital expenditures of $2.6 million related primarily to the Shackleton 2008/2009 winter drilling program. The result of these activities was net debt decreased during the fourth quarter by $2.1 million to $6.4 million at December 31, 2008.
Outlook
The Company will continue developing its Shackleton, Saskatchewan shallow gas property in 2009. During the first quarter of 2009 the Company drilled and placed on production 32 (16 net) gas wells in the Shackleton area which increased our net production to over 1,250 boe per day in early March of 2009. Production for the first quarter of 2009 is expected to average 1,000 boe per day based on field estimates received to date.
During the first quarter of 2009 Ironhorse drilled two (0.4 net) Nisku oil wells in the Pembina, Alberta area. Both wells will be completed after April 1, 2009 and work has begun to place the wells on production. We expect these wells will be placed on production early in the fourth quarter of 2009. These wells are initially expected to increase our net production by 150 boe per day and once we establish a pressure maintenance scheme they should increase our net production by 600 - 800 boe per day. These estimates of production rates are based on management's analysis of the well logs, flow test data and comparisons to analogous wells in the area. Actual production rates and the timing for placing the wells on production could be materially different due to factors beyond our control including regulatory approvals. The addition of these oil wells will provide Ironhorse with a more balanced gas/oil production mix.
Year over year increases in production in 2009 are expected to be offset by lower oil and gas commodity prices. As a result the Company is closely monitoring its capital expenditures for the balance of 2009 with a priority to placing the Pembina oil wells on production and fulfilling our flow-through share expenditure obligations.
Ironhorse remains committed to its strategy of exploring for and developing new focus areas through a combination of "grass roots" exploration and by evaluating asset and corporate acquisition candidates.
Impact of Current Economic Volatility and Uncertainty
The current economic volatility and uncertainty in Canada and around the world has contributed to dramatic decreases in oil and gas commodity prices and restricted access to new capital. In response to these volatile and uncertain times Ironhorse is constantly monitoring its planned capital expenditures, funds from operations and available credit facilities. We believe the Company has sufficient financial resources in 2009 to undertake a $12 million capital program. Highlights of the budget are as follows:
* The 2008/2009 Shackleton drilling program undertaken in the first quarter of 2009 has been substantially completed in the first quarter of 2009 under budget. We estimate actual net costs incurred in the first quarter to be approximately $4.5 million, with costs remaining to be incurred this year estimated at $0.5 million;
* Place the two (0.4 net) Pembina oil wells drilled in the first quarter of 2009 on production in the fourth quarter of 2009, and in the fourth quarter drill the water injection and water source wells necessary for pressure maintenance. Net costs incurred in the first quarter of 2009 with respect to drilling and completing the two wells are estimated at $1.6 million, with the net cost of placing the wells on production including completion, equipping and pipelining estimated at $2.5 million, and the net cost of establishing a pressure maintenance scheme estimated at $0.7 million and
* Fulfill remaining flow-through share expenditure obligations which are estimated at $2.2 million.
The Company currently has a $14.5 million credit facility which we expect will be renewed at current or slightly higher levels as a result of the drilling successes to date in 2009. Further declines in gas prices could negatively impact the amount of the credit facility available. At December 31, 2008 we had drawn $6.4 million, leaving approximately $8 million to finance capital expenditures in 2009. Management believes funds from operations will be sufficient to finance the remaining planned capital expenditures and provide financial flexibility should production rates or commodity prices decline.
Funds from operations for 2009 are budgeted to exceed $6 million. Actual results will vary depending on oil and gas commodity prices, production declines on our Shackleton gas wells and the timing for placing the Pembina wells on production. Our current estimate for funds from operations assumes production will average 1,150 to 1,250 boe per day with the Shackleton gas wells experiencing similar decline rates as wells drilled in prior years and the Pembina oil wells being placed on production in the fourth quarter. Gas prices are assumed to average $5.00 per mcf for the year and oil prices in the fourth quarter of 2009 will average $50 per bbl at the wellhead. Given that all the Shackleton gas wells were placed on production prior to March 15, 2009, we believe the greatest risk in our estimate for funds from operations stems from greater than expected declines from the new gas wells, delays in tying in the Pembina oil wells and lower than expected gas prices. Management is continually reviewing its operations and making adjustments to its capital expenditures to accommodate differences between assumptions made and actual results.
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Years Ended December 31
SELECTED INFORMATION 2008 2007 2006
Thousands except per share amounts
Financial
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Revenue 17,965 9,041 2,766
Royalties (6,883) (3,410) (1,092)
Funds from operations 8,001 3,529 1,050
Net income (loss) 1,586 (812) (733)
Net income (loss) per share
basic and diluted 0.08 (0.04) (0.04)
Total assets 32,199 25,843 16,849
Capital expenditures 10,556 12,406 13,913
Net debt (6,789) (7,983) (4,337)
Weighted average shares outstanding
- basic 20,225 19,411 16,346
- fully diluted 20,352 19,411 16,346
Operations
Production
Gas - mcf/d 6,434 3,977 1,162
Oil & ngls - bbl/d 7 7 8
Total - boe/d 1,079 670 202
Average sales price
Gas - $/mcf 7.52 6.09 5.92
Oil - $/bbl 67.00 71.06 66.18
Royalty - $/boe 17.42 13.95 14.82
Operating expenses - $/boe 2.29 3.32 4.30
Field Netback - $/boe 25.74 19.68 17.66
General & administrative expenses
- $/boe 3.44 3.64 3.91
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OPERATIONS
Our operations are focused in Shackleton, Saskatchewan, Pembina, Alberta and NE British Columbia. In addition to these areas, we are constantly evaluating new areas which have the potential to become a focus area.
Shackleton is a shallow gas development project. We have drilled and placed on production 100 (50 net) gas wells over the past four winters. We are evaluating the economics of an infill drilling program which would see the Company drill up to 100 (50 net) additional gas wells. The economics of this project would be significantly enhanced if one or more of the following were to occur: fall access as opposed to "winter only" drilling would significantly reduce drilling costs; higher gas prices; lower royalties; or some combination of all of the above.
We participated in a significant oil discovery in the Pembina area this winter. We have drilled two (0.4 net) Nisku oil wells which we are working towards placing on production in the fourth quarter of 2009. These two oil wells will initially be subject to a combined production allowable of approximately 700 to 800 (130 to 150 net) boe per day. Once a pressure maintenance scheme is established Ironhorse expects to increase production from the two oil wells to a combined rate of approximately 3,000 to 4,000 (600 to 800 net) boe per day. Ironhorse's net capital costs, to place the two oil wells on production, is estimated to be $2.5 million. The Company's net cost of a pressure maintenance scheme is estimated at $0.7 million. Ironhorse has the ability to finance these activities with currently available credit facilities and funds from operations. The timing and costs for undertaking these activities represents our best estimate at this time. Various factors beyond the Company's control, including regulatory approvals, could result in delays.
NE British Columbia is our newest focus area. In 2008 we acquired crown lands and trade seismic and are planning to drill a well (0.5 net) later this year.
Sales Volumes
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Three Months Ended December 31 Year Ended December 31
2008 2007 CHANGE 2008 2007 CHANGE
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Daily sales volumes
Natural gas mcf/d 5,486 3,934 39% 6,434 3,977 62%
Light oil &
ngls bbls/d 7 8 (13%) 7 7 0%
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Total boe/d 921 664 39% 1,079 670 61%
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Sales volumes for the year ended December 31, 2008 averaged 1,079 boe per day, an increase of 61% from the 670 boe per day during the corresponding period in 2007. Natural gas volumes increased to 6,434 mcf per day, a 62% increase from the corresponding 2007 period volume of 3,977 mcf per day. The increase in natural gas production is the result of the first quarter drilling program which resulted in an additional 31 (15 net) gas wells being placed on production in the Shackleton area, bringing the total number of producing wells to 68 (34 net). The Company experienced natural declines on its gas production during the year which resulted in an exit rate of approximately 875 boe per day at the end of December 2008.
Sales volumes at the Shackleton property have increased during the first quarter of 2009 when we placed an additional 32 (16 net) gas wells on production. Our net production rate increased to over 1,250 boe per day in March. The new Shackleton gas wells are expected to experience similar decline rates to wells drilled in previous years. Our Pembina Nisku oil discoveries are expected to be on production in the fourth quarter of 2009. The initial production allowable rates for the wells will be approximately 700-800 (130 to 150 net) boe per day. Once a pressure maintenance scheme is established production from the wells is expected to increase to 3,000 to 4,000 (600 to 800 net) boe per day. We plan on having the pressure maintenance scheme in place by the first quarter of 2010. The timing and cost for these undertakings represents our best estimate at this time, various factors beyond the Company's control including regulatory approvals could result in delays.
The Company estimates 2009 production will average 1,150 to 1,250 boe per day assuming the new Schackleton gas wells perform consistent with prior years and the Pembina oil wells are placed on production in the fourth quarter of 2009 at their initial production allowable rates. Actual results could differ significantly from these estimates due to factors beyond management's control including regulatory delays.
Marketing and Revenue
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Three Months Ended December 31 Year Ended December 31
Commodity Pricing 2008 2007 CHANGE 2008 2007 CHANGE
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Benchmark
Alberta Spot
- Natural gas $/mcf 6.77 6.19 9% 8.18 6.48 26%
West Texas
Intermediate
- Oil US$/bbl 58.45 90.73 (36%) 99.20 72.37 37%
Edmonton Par
- Oil $/bbl 65.59 86.79 (24%) 102.95 76.65 34%
Company Prices
Natural gas
price $/mcf 6.72 5.99 12% 7.52 6.13 23%
Light oil
price $/bbl 54.41 76.97 (29%) 92.47 71.06 30%
Boe $/boe 40.40 36.47 11% 45.45 36.95 23%
Revenue
Natural gas $m 3,390 2,170 56% 17,714 8,846 100%
Light oil & ngls $m 34 57 (40%) 241 186 30%
Other $m 3 - - 10 9 11%
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Total $m 3,427 2,227 54% 17,965 9,041 99%
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The Company's Shackleton gas production is marketed through the marketing arm of a large international oil and gas company. Ironhorse's gas receives the Alberta gas spot price plus $0.02 per gigajoule ("GJ") less a transportation charge of approximately $0.13 per GJ. Alberta spot gas prices are based on Natural Gas Exchange prices at the AECO Hub. Natural gas pricing tends to be volatile and is affected by supply and demand, storage levels, weather conditions and fuel switching to alternative sources of energy. Alberta spot natural gas prices increased 26% in 2008 compared to 2007. Gas prices peaked in the second quarter of 2008 and have generally drifted down throughout the balance of 2008 and early 2009. During 2008 approximately 75% of Ironhorse's natural gas production was sold on the spot market and 25% was sold at contracted prices. As a result of the contracted pricing agreements Ironhorse's realized gas price was approximately $0.20 per mcf lower than it would have been if all the gas had been sold at spot prices. The Company's natural gas receives a price which is lower than the average benchmark price due to the lower heat content per mcf for Shackleton natural gas.
The Company monitors the impact of commodity price exposure and from time to time, enters into structured sales contracts such as swaps, options or collars for fixed periods of time to mitigate commodity price risk. The objective of this strategy is to reduce the Company's risk exposure to changes in funds from operations resulting from changes in commodity prices, thereby ensuring our ability to complete the planned capital investment program.
Management entered into the following natural gas sales contracts with respect to 2008/2009:
* For the period April 1, 2008 to October 31, 2008 the Company entered into a fixed price natural gas sales contract for 2,000 GJ per day at $7.05 per GJ.
* For the 2008/2009 winter heating season covering November 1, 2008 to March 31, 2009, Ironhorse entered into two "costless collar" physical natural gas sales contracts. One contract is for 1,000 GJ per day based on a floor price of $7.75 per GJ and a ceiling price of $9.45 per GJ. The other contract is for 500 GJ per day with a floor price of $8.00 per GJ and a ceiling price of $10.00 per GJ.
* For the period covering April 1, 2009 to October 31, 2009, the Company has entered into three physical natural gas sales contracts. The first is a fixed price contract of $4.03 per GJ for 1,000 GJ per day. The second is a costless collar with a floor price of $3.50 per GJ and a ceiling of $4.52 per GJ for 500 GJ per day. The third contract is a three way collar with a floor of $3.50 per GJ and a ceiling of $4.85per GJ and a put for $2.75 per GJ for 500 GJ per day. The three way collar works as follows: if the gas price is between $2.75 and $3.50 per GJ then price received is $3.50 per GJ. If the gas price is below $2.75 per GJ then the price received by the Company is spot plus $0.75 per GJ.
Revenues for the year ended December 31, 2008 were reduced by $0.4 million as a result of these natural gas price contracts. If the remaining contracts had been closed out on December 31, 2008 the Company would have realized a gain of approximately $0.25 million.
Sales revenues for the year ended December 31, 2008 increased 99% to $18 million from $9 million in 2007 as a result of the increase in sales volumes and higher natural gas prices.
The sales revenues for the quarter ended December 31, 2008 were $3.4 million, an increase of 54% over the $2.2 million in the corresponding period in 2007. Sales revenues for the fourth quarter of 2008 were increased by $0.2 million due to the gas price contracts discussed above.
Sales revenues in 2009 will be positively influenced by increased production from the wells drilled in Shackleton and Pembina and negatively impacted if commodity prices for oil and natural gas remain at current or lower levels.
Royalties
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Three Months Ended December 31 Year Ended December 31
2008 2007 CHANGE 2008 2007 CHANGE
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Royalties $m 1,098 832 32% 6,883 3,410 102%
Royalties per boe $ 12.95 13.63 (5%) 17.42 13.95 25%
Royalty rate % 32.07 37.36 (14%) 38.34 37.75 2%
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Ironhorse's producing wells are subject to crown, First Nation and overriding royalties which are payable to the owners of the mineral rights. The mineral rights for Company's Shackleton property are owned by the Carry the Kettle First Nation and are subject to a lessor royalty and a gross overriding royalty. The lessor royalty is equivalent to Saskatchewan crown royalty and the gross overriding royalty is a sliding scale minimum 15%. Royalty rates vary based on a number of factors including commodity and reference pricing and production rates. Royalties are calculated on sales revenues based on daily spot prices and without reference to gas price contract adjustments.
For the year ended December 31, 2008 royalties increased 102% to $6.9 million ($17.42 per boe) compared to $3.4 million ($13.95 per boe) in 2007. The increase in royalties for the period is attributable to increased natural gas production and higher natural gas prices.
Royalties for the fourth quarter of 2008 increased 32% to $1.1 million ($12.95 per boe) compared to $0.8 million ($10.80 per boe) for 2007. The royalty rate during the quarter was 32.07% of sales compared to 37.36% in the same period of 2007. The increase in royalties paid during the quarter was due to increased production and higher natural gas prices. The lower royalty rate per boe is due to higher revenues from gas price contract adjustments in the fourth quarter which increased revenues by $0.2 million.
Royalties are expected to be approximately 28 - 32% in 2009, depending on gas prices, until such time as the Pembina oil wells are placed on production. The first 50,000 barrels of gross production from each of the Pembina oil wells is eligible for the reduced royalty rate of 5% announced by the Alberta provincial government on March 2, 2009. The announcement also includes drilling incentives in the form of royalty credits for wells drilled from April 1, 2009 to April 1, 2010. To the extent that the Company fulfills its outstanding flow through expenditure commitments by drilling wells in Alberta, it will earn additional royalty relief.
Operating Expenses
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Three Months Ended December 31 Year Ended December 31
2008 2007 CHANGE 2008 2007 CHANGE
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Operating expenses $m 261 262 0% 903 812 11%
Per boe $ 3.08 4.29 (28%) 2.29 3.32 (31%)
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Operating expenses were $0.3 million, or $3.08 per boe, for the quarter ended December 31, 2008 consistent with the $0.3 million or $4.29 per boe, during the comparable period of 2007. The lower rate per boe was due to higher production levels in the period.
Operating expenses for the year ended December 31, 2008 increased 11% to $0.9 million ($2.29 per boe) from $0.8 million ($3.32 per boe) during the corresponding period in 2007. The lower cost per boe is attributable to improved economies of scale from increased production.
Operating expenditures in 2009 are expected to be $2.00 - $2.50 per boe. Our operating expenses on a boe basis compare favourably to peers in the industry as we own the infrastructure necessary to produce the gas at Shackleton.
General and Administrative Expense ("G&A") and Stock Based Compensation ("SBC")
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Three Months Ended December 31 Year Ended December 31
2008 2007 CHANGE 2008 2007 CHANGE
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G&A $m 405 224 81% 1,356 891 52%
SBC $m 86 121 (29%) 514 422 22%
Per boe:
G&A $ 4.78 3.67 30% 3.44 3.64 (5%)
SBC $ 1.01 1.98 (49%) 1.30 1.72 (25%)
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For the quarter ended December 31, 2008, G&A increased 81% from $0.2 million to $0.4 million due to higher management fees and fees paid to third party consultants.
For the year ended December 31, 2008 G&A increased 52% to $1.4 million from $0.9 million in the same period in 2007 largely due to higher management fees.
Management fees charged to G&A are based on the Company's production profile, the fee increased from $1.75 per producing boe to $2.35 per boe effective April 1, 2008. The higher fee per boe combined with increases in production resulted in management fees increasing from $0.4 million in 2007 to $0.7 million in 2008. For additional information on management fees refer to the related party section of this MD&A.
SBC decreased by 29% in the current quarter as compared to the corresponding quarter in 2007 with an increase overall of 22% for the year ended December 31, 2008 as compared with 2007. The increase in SBC was the result of option holders exercising their options pursuant to the "cashless exercise" alternative wherein the option holder receives a cash payment equal to the difference between the exercise price and the market price multiplied by the number of options exercised in lieu of purchasing shares at the exercise price and the issuance of additional options in 2008.
G&A and SBC are expected to remain at approximately $3.50 and $1.00 per boe respectively in 2009.
Interest Expense
-***-
Three Months Ended December 31 Year Ended December 31
2008 2007 CHANGE 2008 2007 CHANGE
-------------------------------------------------------------------------
Interest expense $m 127 107 19% 544 308 77%
Per boe $ 1.50 1.75 (15%) 1.38 1.26 10%
-------------------------------------------------------------------------
-****-
Interest expense for the year ended December 31, 2008 was $0.5 million compared to $0.3 million for 2007.
Interest expense for the three months ended December 31, 2008 was $0.1 million compared to $0.1 million for 2007.
The increase in interest expense during 2008 is due to an increase in bank debt as a result of our ongoing drilling programs in 2007 and the first quarter of 2008.
The Company expects interest expense to decrease in 2009 due to lower interest rates and bank debt remaining at levels consistent with 2008.
Depletion, Depreciation and Accretion
-***-
Three Months Ended December 31 Year Ended December 31
2008 2007 CHANGE 2008 2007 CHANGE
-------------------------------------------------------------------------
Depletion, depreciation
and accretion $m 1,406 982 43% 5,507 4,261 29%
Per boe $ 16.59 16.08 3% 13.94 17.43 (20%)
-------------------------------------------------------------------------
-****-
For the year ended December 31, 2008, depletion, depreciation and accretion ("DD&A") increased 29% from $4.3 million in 2007 to $5.5 million in 2008. The DD&A provision for the three months ended December 31, 2008 increased 43% from $0.9 million to $1.4 million. Both increases are due to increased production volumes and higher capital base in 2008 over 2007. On a per boe basis, the DD&A ratio decreased by 20% in 2008 due to reduced pro-rata capital expenditures relative to the reserve additions in the year.
The depletion, depreciation and accretion rate per boe for 2009 is expected to remain the same or trend downwards given the oil discoveries made in the Pembina, Alberta area. The Company will have a better indication of the impact of the Pembina oil discovery in the second quarter of 2009 when we receive an updated independent evaluation of our reserves.
Income Taxes
-***-
Three Months Ended December 31 Year Ended December 31
2008 2007 2008 2007
-------------------------------------------------------------------------
Income Taxes $m (84) (38) 672 (251)
-------------------------------------------------------------------------
-****-
Future income taxes for the year ended December 31, 2008 were $0.7 million compared to a reduction of $0.3 million for 2007. The change is consistent with the transition from a loss to income before taxes.
At December 31, 2008, the Company had estimated resource tax pools and tax losses of approximately $23 million. Ironhorse does not expect to be taxable in the next two years, given the forecasted level of capital expenditures and current commodity prices. As at December 31, 2008 Ironhorse had $3.5 million of Canadian exploration expenditures to be incurred prior to December 31, 2009, pursuant to a 2008 flow- through share offering.
Field Netback
-***-
Three Months Ended December 31 Year Ended December 31
$ Per boe 2008 2007 2008 2007
-------------------------------------------------------------------------
Revenue 40.40 36.47 45.45 36.95
Less: Royalties 12.95 13.63 17.42 13.95
Operating expenses 3.08 4.29 2.29 3.32
-------------------------------------------------------------------------
Field netback 24.37 18.55 25.74 19.68
-------------------------------------------------------------------------
-****-
Ironhorse's field netback per boe for the year ended December 31, 2008 increased 31% to $25.74 from $19.68 per boe for the corresponding 2007 period.
For the quarter ended December 31 the field netback increased 31% from $18.55 in 2007 to $24.37 in 2008.
The higher field netbacks were a result of higher natural gas prices and lower operating expenses which were partially offset by increased royalties.
Field netbacks in 2009 are expected to be lower due to falling oil and gas commodity prices.
Funds from Operations and Earnings (Loss)
-***-
Three Months Ended December 31 Year Ended December 31
2008 2007 CHANGE 2008 2007 CHANGE
-------------------------------------------------------------------------
Funds from
operations $m 1,525 738 107% 8,001 3,529 127%
Basic per share $ 0.07 0.03 133% 0.40 0.18 122%
Diluted per
share $ 0.07 0.03 133% 0.39 0.18 117%
Income (loss) $m 96 (262) 1,586 (812)
Basic per share $ 0.00 (0.01) 0.08 (0.04)
Diluted per
share $ 0.00 (0.01) 0.08 (0.04)
Weighted average shares outstanding
Basic m 21,779 19,488 12% 20,225 19,411 4%
Diluted m 21,906 20,013 9% 20,352 20,034 2%
-------------------------------------------------------------------------
-****-
Funds from operations for the year ended December 31, 2008 increased 127% to $8 million from $3.5 million in 2007.
Funds from operations for the three months ended December 31, 2008 increased 107% to $1.5 million from $0.7 million in 2007.
The increase in funds from operations for both periods was due principally to increased natural gas production and higher natural gas prices.
Funds from operations were calculated as follows:
-***-
Three Months Ended December 31 Year Ended December 31
2008 2007 2008 2007
-------------------------------------------------------------------------
Income (loss) $m 128 (262) 1,586 (812)
Add/(subtract):
Depletion, depreciation
and accretion $m 1,406 982 5,507 4,261
Stock-based compensation $m 86 56 264 357
Future income taxes $m (84) (38) 672 (251)
Abandonment costs incurred $m (11) - (28) (26)
-------------------------------------------------------------------------
Funds from operations $m 1,525 738 8,001 3,529
-------------------------------------------------------------------------
-****-
Capital Expenditures
-***-
Expenditure
Category Three Months Ended December 31 Year Ended December 31
$m 2008 2007 CHANGE 2008 2007 CHANGE
-------------------------------------------------------------------------
Land 230 (299) 1,434 1,532 (6%)
Seismic 49 22 123% 144 159 (9%)
Drilling and
completions 1,215 674 80% 6,326 7,976 (21%)
Facilities,
pipelines and
equipment 1,321 1,396 (5%) 2,505 2,554 (2%)
G&A 27 44 (39%) 157 185 (15%)
-------------------------------------------------------------------------
2,842 1,837 55% 10,566 12,406 (15%)
-------------------------------------------------------------------------
AREA Three Months Ended December 31 Year Ended December 31
$m 2008 2007 CHANGE 2008 2007 CHANGE
-------------------------------------------------------------------------
Saskatchewan 2,302 1,767 30% 9,419 10,404 (9%)
NE British Columbia 341 24 1,321% 710 1,749 (59%)
Alberta 172 2 8,500% 280 68 312%
G&A 27 44 (39%) 157 185 (15%)
-------------------------------------------------------------------------
2,842 1,837 55% 10,566 12,406 (15%)
-------------------------------------------------------------------------
-****-
Capital expenditures decreased 15% from $12.4 million in 2007 to $10.6 million in 2008 primarily as a result of the Company spending less in the Shackleton and NE British Columbia areas. In Shackleton the company achieved additional cost efficiencies with respect to drilling and infrastructure. In NE British Columbia the Company acquired land and seismic whereas in 2007 the Company participated in drilling a well.
Capital expenditures increased 55% from $1.8 million to $2.8 million for the three months ended December 31, 2008 as the Company undertook preparations for its 2008/2009 winter drilling program in the Shackleton, Saskatchewan and Pembina, Alberta areas.
Related Party Transactions
Ironhorse is party to a management services agreement with Grizzly Resources Ltd. ("GRL") a company related by virtue of common management. Pursuant to the terms of the agreement GRL provides technical and administrative services typically required in operating an oil and gas company. This arrangement has provided Ironhorse with the benefits of accessing a larger more comprehensive pool of technical and administrative services than it could otherwise afford during its early stage of development. The management contract charges Ironhorse a fee based on units of production and a percentage of capital expenditures. The production fee is charged to G&A and is calculated on a producing boe basis. Effective April 1 2008, the fee per boe was increased from $1.75 to $2.35 per boe. The amount charged is reduced by all "monthly well operating overhead" charges. The fee on capital expenditures is capitalized to property and equipment. This fee was increased from three to four percent of the capital expenditures effective April 1 2008, and is reduced by all "capital overhead" charges which otherwise flow through the joint interest billings.
-***-
------------------------------------------
YEAR ENDED DECEMBER 31
2008 2007
------------------------------------------
Production fees $m 729 354
Capital fees $m 156 185
------------------------------------------
Management fees $m 885 539
------------------------------------------
-****-
Normal Course Issuer Bid
On December 1, 2008 the Company reactivated its program to purchase its common shares from time to time in accordance with the normal course issuer bid procedures under Canadian securities law.
Pursuant to the terms of the current issuer bid, Ironhorse may purchase for cancellation, as Ironhorse considers advisable, up to a maximum of 1,493,459 common shares during the 12 month period commencing December 1, 2008. The purchases will be made on the open market through the TSX Venture Exchange. PI International Corp. is the brokerage firm conducting the normal course issuer bid on behalf of the Company.
Ironhorse believes that the purchase of its common shares will create shareholder value as recent market prices for its common shares do not always reflect the underlying value of its oil and gas reserves. To the extent that the Company is able to purchase shares on the open market for cancellation there is a proportionate increase in the value attributable to remaining outstanding common shares.
During the year ended December 31, 2008, the Company acquired 73,400 common shares at an average cost of $1.03 per share. To date in 2009, the Company has acquired 92,700 common shares at an average cost of $1.31 per share.
Liquidity and Capital Resources
Oil and gas exploration and development is a capital intensive business. Periodic infusions of additional capital may be required to accelerate the rate of the Company's growth. Ironhorse chooses to finance its ongoing capital expenditure program through a combination of reinvesting funds from operations, bank borrowing and additional share equity.
The Company had drawn $6.4 million against its $14.5 million credit facility at December 31, 2008. The Company's credit facility, reviewable semi-annually, is with a Canadian chartered bank. Advances bear interest at the bank's prime lending rate plus 0.25% or at prevailing bankers' acceptance rate plus an applicable bank fee. The loan is secured by all of the Company's assets. Principal repayments are required only if the borrowing base is exceeded. Ironhorse expects to receive a favourable review of its credit facility as increases in the Company's proven producing reserves should more than offset lower commodity prices.
The Company believes it can finance its planned 2009 capital expenditures from funds from operations and existing credit facilities. The priorities for 2009 include:
* Drilling and placing on production 32 (16 net) gas wells in Shackleton, which was completed in the first quarter of 2009;
* Placing the Pembina oil discoveries which were drilled in the first quarter of 2009 on production in the fourth quarter of 2009 and
* Fulfilling our remaining exploration flow-through expenditure commitments which are estimated at $2.2 million
Ironhorse believes it can complete these activities with its current financial resources. However if natural gas prices were to decrease significantly from current levels for a sustained period of time, this may impact the timing of the above activities. See "Impact of Current Economic Volatility and Uncertainty"
Ironhorse has 21,816,043 common shares and 2,061,500 stock options with a weighted average exercise price of $1.48 per share outstanding as at March 16, 2009.
Contractual Obligations
Ironhorse has various contractual obligations and commitments arising in the normal course of operations and financing activities. These obligations and commitments have been considered when assessing the cash requirements in the above discussion of future liquidity.
The Company issued flow-through common shares in 2007 and 2008. Pursuant to the terms of the financings, the Company is obligated to spend the gross proceeds on qualifying Canadian exploration and development expenditures. As at December 31, 2008, Ironhorse had obligations to incur $3.5 million of Canadian exploration expenditures in 2009 to fulfill all of its flow-through financing obligations. As of today's date we estimate that that the Company has incurred approximately $1.2 million of qualifying expenditures in 2009 leaving a balance of $2.2 million of qualifying expenditures to be incurred through out the balance of 2009.
Critical Accounting Estimates
The preparation of the Company's financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported financial results of the Company. On an on-going basis, management reviews its estimates in light of currently available information. Changes in facts and circumstances may require revisions to estimates causing changes to reported results. Ironhorse's critical accounting estimates are discussed below.
Oil and Gas Accounting
Ironhorse follows the full-cost accounting guideline to account for its petroleum and natural gas operations. Under this method, all costs associated with the exploration for and development of petroleum and natural gas reserves are capitalized in one Canadian cost centre. These capitalized costs, along with estimated future development costs, are depleted and depreciated on a unit-of-production basis using estimated proved petroleum and natural gas reserves. By their inclusion in the unit-of-production calculation, reserve estimates are a significant component of the calculation of depletion and depreciation expense.
Independent engineers engaged by the Company use all available geological, reservoir, and production performance data to prepare the reserve estimates. These estimates are reviewed and revised, either upward or downward, as new information becomes available. Revisions are necessary due to changes in assumptions based on reservoir performance, commodity prices, economic conditions, government regulations and other relevant factors. If reserve estimates are revised downward, net income could be affected by increased depletion and depreciation.
Impairment of Petroleum and Natural Gas Assets
Companies that use the full-cost method of accounting for oil and natural gas operations are required to perform an impairment test (the "ceiling test") that calculates a limit for the net carrying cost of petroleum and natural gas assets. The net amount at which petroleum and natural gas properties are carried is subject to a cost recovery test. The ceiling test is a two-stage process. The first stage of the test is a recovery test which compares the undiscounted future cash flows from proved reserves at forecast prices plus the cost, less impairment, of unproved properties to the net book value of the petroleum and natural gas assets to determine if the assets are impaired. An impairment loss exists when the net book value of the petroleum and natural gas assets exceeds such undiscounted cash flows. The second stage determines the amount of the impairment loss to be recorded. The impairment is measured as the amount by which the net book value of the petroleum and natural gas assets exceeds the future discounted cash flows from proved plus probable reserves at the forecast prices. If reserve estimates are revised downward, net income could be affected by any additional depletion and depreciation recorded under the ceiling test calculation and could result in a significant accounting expense for a particular period. Ironhorse had approximately a $24 million cushion pursuant to the first test at December 31, 2008.
Asset Retirement Obligations
The amounts recorded for asset retirement obligations are estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and the facilities and the estimated time period during which these costs will be incurred in the future. Any changes to these estimates could change the amount recorded for asset retirement obligations and may materially impact the financial statements of future periods.
Changes in Accounting Policies
Effective January 1, 2008, the Company adopted the Canadian Institute of Chartered Accountants (CICA) recommendations for capital disclosures which require disclosure of qualitative and quantitative information regarding the Company's objectives, policies and processes for managing capital (refer to Note 10 to the financial statements).
Effective January 1, 2008, the Company adopted the CICA recommendations pertaining to disclosure and presentation of financial instruments which require disclosure of the classification of the Company's financial instruments and additional qualitative and quantitative information regarding the nature and extent of risks arising from financial instruments to which the Company is exposed (refer to Note 11 to the financial statements).
Financial Instruments
Ironhorse's financial instruments consist of cash, accounts receivable and accounts payable, accrued liabilities and bank loan payable. Unless otherwise noted, it is management's opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments. The fair value of these financial instruments is their carrying value due to their short-term maturity and capacity for prompt liquidation.
IFRS Changeover Plan
The conversion to IFRS, effective January 1, 2011, represents a one-time implementation of multiple accounting standards which differ significantly from Canadian GAAP. The scope of the conversion project extends beyond accounting issues as it will need to also address changes to information systems, internal controls over financial reporting and disclosure controls and procedures and related business issues such as terms of contracts affected by accounting measures. Ironhorse has initiated a conversion plan which will take the Company through the various decisions and milestones which need to be addressed over the next two years to ensure an orderly conversion to IFRS. To assist in communicating what needs to be done and what has been done the Company will provide updates in its MD&A over the next two years with respect to its conversion plan
-***-
-------------------------------------------------------
Key Activity Milestones/Deadlines
- selected elements
only
-------------------------------------------------------
Financial Statement
Preparation Ready for commencement
Identify differences of 2010 financial year
Between Canadian GAAP Quantification of effects
and IFRS accounting policies of change for IFRS 1
Choose IFRS policies. disclosure and
Identify additional IFRS comparative 2010
disclosure requirements financial statements
Develop financial statement including note disclosure
format by end of Q3 2010
Assess impact and tax and
regulatory reporting
Quantifications of IFRS 1
disclosures for 2010
Systems and Processes
Develop new chart of Ready for conversion
accounts beginning of Q4 2009
IFRS expertise identification Ready for parallel
and development at all levels processing of general
including board level ledger before 2010
Map accounts to GAAP
basis to IFRS basis
Identify how to reconcile
back to GAAP for transition
year 2010
Document IFRS processes
Investor Relations /
Stakeholder Communicate significance
Communications and impact of changes as
Educate analysts, investors they become know
And employees on the impact
of IFRS
-----------------------------
Effort Accomplished by
December 31, 2008
-----------------------------
Significant accounting policy
choices identified
Internal committee comprised
of senior personnel meeting
weekly
Expert resources/training
program commenced
Ongoing discussions with
accounting systems provider
Quarterly updates in the
MD&A
-****-
Selected Quarterly Information
-***-
------------------------------------------------------------------
2008
Unit Q4 Q3 Q2 Q1
------------------------------------------------------------------
Financial
Revenue $m 3,427 4,355 6,120 4,063
Funds from operations $m 1,525 1,806 2,939 1,731
Per share - basic $ 0.07 0.09 0.15 0.09
Per share - diluted $ 0.07 0.09 0.14 0.09
Income (loss) $m 128 227 919 312
Per share - basic $ 0.00 0.01 0.05 0.02
Per share - diluted $ 0.00 0.01 0.05 0.02
Capital expenditures $m 2,842 366 1,416 5,942
Net debt $m 6,789 8,645 10,023 12,205
Total assets $m 32,199 31,070 32,600 32,098
Operational
Production
Natural gas mcf/d 5,486 6,624 7,600 6,034
Light oil & Ngls bbls/d 7 7 7 6
Total sales boe/d 921 1,111 1,143 1,012
Average price
Natural gas $/mcf 6.72 6.99 8.74 7.29
Light oil & Ngls $/bbl 54.41 114.82 103.61 102.61
Boe $/boe 40.41 42.61 52.80 44.13
Field Netback $/boe 24.37 24.95 29.28 23.50
Weighted average shares outstanding
Basic m 21,780 20,111 19,979 19,500
Diluted m 21,906 20,489 20,376 19,509
------------------------------------------------------------------
2007
Unit Q4 Q3 Q2 Q1
------------------------------------------------------------------
Financial
Revenue $m 2,227 2,169 3,121 1,524
Funds from operations $m 738 894 1,325 572
Per share - basic $ 0.04 0.05 0.08 0.03
Per share - diluted $ 0.04 0.04 0.07 0.03
Income (loss) $m (263) (253) (115) (181)
Per share - basic $ (0.01) (0.01) (0.01) (0.01)
Per share - diluted $ (0.01) (0.01) (0.01) (0.01)
Capital expenditures $m 1,836 244 369 9,957
Net debt $m 7,983 7,231 7,333 7,966
Total assets $m 25,271 26,016 27,108 25,843
OPERATIONAL
Production
Natural gas mcf/d 3,935 4,428 5,030 2,494
Light oil & Ngls bbls/d 8 10 6 5
Total sales boe/d 664 748 844 421
Average price
Natural gas $/mcf 6.11 5.16 6.74 6.64
Light oil & Ngls $/bbl 74.11 73.68 68.84 58.54
Boe $/boe 36.47 31.53 40.62 40.06
Field Netback $/boe 18.56 18.24 22.11 19.16
Weighted average shares outstanding
Basic m 19,488 19,557 19,705 18,886
Diluted m 20,013 20,112 20,316 19,548
-****-
Ironhorse's fourth quarter 2008 growth in revenue, funds from operations and net income is primarily attributable to the successful first quarter drilling program and higher natural gas prices. First quarter 2009 operating results are expected to reflect increased gas production as a result of wells drilled and placed on production and be offset by lower natural gas prices. During the first quarter of 2009 the Company also drilled two successful Nisku oil wells at Pembina, Alberta which we plan to place on production early in the fourth quarter of 2009.
The Company's operating results over the past eight quarters reflect the ongoing development of its shallow gas project in Shakleton, Saskatchewan which has resulted in increased production, revenues and cash flow from operations.
ADDITIONAL INFORMATION
Additional information regarding Ironhorse Oil & Gas Inc., including the Company's Annual Information Form, is available on SEDAR at www.sedar.com or on the Company's website at www.ihorse.ca.
Management's Report
Management, in accordance with Canadian generally accepted accounting principles, has prepared the accompanying financial statements of Ironhorse Oil & Gas Inc. Management is responsible for the integrity of the financial information. Internal control systems are designed and maintained to provide a reasonable assurance that the assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.
Kenway Mack Slusarchuk Stewart LLP was appointed by the Ironhorse Oil & Gas Inc.'s shareholders to express an opinion on the financial statements. Their examination included such tests and procedures, as they considered necessary, to provide reasonable assurance that the financial statements are presented fairly in accordance with the Canadian generally accepted accounting principles.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises the responsibility through the Audit Committee, with assistance from the Reserves Committee regarding the annual review of our petroleum and natural gas reserves. The Audit Committee meets regularly with management and the independent auditors to ensure that management's responsibilities are properly discharged, to review the financial statements and recommend that the financial statements be presented to the Board of Directors for approval. The Audit Committee also considers the independence of the external auditors, their fees and, for review by the Board of Directors and approval by the shareholders, their engagement or re-appointment. The external auditors have access to the Audit Committee without the presence of management.
signed "Larry J. Parks" signed "Rob Solinger"
Larry J. Parks Rob Solinger
President & Chief Executive Officer Vice President, Finance &
Chief Financial Officer
March 16, 2009
Auditors' Report
To: The Shareholders of
Ironhorse Oil & Gas Inc.
We have audited the balance sheets of Ironhorse Oil & Gas Inc. as at December 31, 2008 and 2007 and the statements of net income (loss), comprehensive income (loss) and deficit, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2008 and 2007 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.
signed "Kenway Mack Slusarchuk Stewart LLP"
Chartered Accountants
February 25, 2009
Calgary, Alberta
Ironhorse Oil & Gas Inc.
Balance Sheet
-***-
--------------------------------------------------------------
December 31 December 31
(Thousands Of Dollars) 2008 2007
--------------------------------------------------------------
Assets
$
Current assets 7 $ 44
Accounts receivable 1,821 882
--------------------------------------------------------------
1,828 926
Petroleum and natural gas properties
(note 4) 30,371 24,917
--------------------------------------------------------------
$ 32,199 $ 25,843
--------------------------------------------------------------
Liabilities
Current liabilities
Accounts payable and $ $
accrued liabilities 2,177 2,015
Bank loan (note 5) 6,440 6,894
--------------------------------------------------------------
8,617 8,909
Asset retirement obligation
(note 6) 1,034 666
Future income taxes
(note 7) 1,772 1,193
--------------------------------------------------------------
11,423 10,768
--------------------------------------------------------------
Shareholders' Equity (note 8)
Share capital 22,842 18,888
Contributed surplus 1,154 994
Deficit (3,220) (4,807)
--------------------------------------------------------------
20,776 15,075
--------------------------------------------------------------
$ 32,199 $ 25,843
--------------------------------------------------------------
-****-
See accompanying notes to financial statements.
Approved on behalf of the Board:
(Signed) "Larry J. Parks"
Director
(Signed) "Gerry C. Quinn"
Director
Ironhorse Oil & Gas Inc.
Statements Of Net Income (Loss),
Comprehensive Income (Loss) and Deficit
-***-
-------------------------------------------------------------------
Year Ended Year Ended
December 31 December 31
(Thousands of dollars except 2008 2007
per share amounts)
-------------------------------------------------------------------
Revenue
Petroleum and natural gas sales $ 17,965 $ 9,041
Royalties (6,883) (3,410)
-------------------------------------------------------------------
11,082 5,631
-------------------------------------------------------------------
Expenses
Operating 903 812
General and administrative 1,356 891
Stock-based compensation (note 8) 514 422
Interest 544 308
Depletion, depreciation and accretion 5,507 4,261
-------------------------------------------------------------------
8,824 6,694
-------------------------------------------------------------------
Income (Loss) Before Taxes 2,258 (1,063)
Future income taxes (recovery (note 7) 672 (251)
-------------------------------------------------------------------
Net Income (Loss) and Comprehensive Income 1,586 (812)
(Loss)
Deficit, beginning of the year (4,806) (3,994)
-------------------------------------------------------------------
$ (4,806)
Deficit, end of the year $ (3,220)
-------------------------------------------------------------------
Net Income (loss) per share (note 8)
Basic $ 0.08 $ (0.04)
Diluted $ 0.08 $ (0.04)
-------------------------------------------------------------------
-****-
See accompanying notes to financial statements.
Ironhorse Oil & Gas Inc.
Statement of Cash Flow
-***-
----------------------------------------------------------------
Year Ended Year Ended
December 31 December 31
(Thousands of dollars) 2008 2007
----------------------------------------------------------------
Cash provided by (used in):
Operating activities
Net income (loss) $ 1,586 $ (812)
Items not affecting cash
Depletion, depreciation
and accretion 5,507 4,261
Stock-based compensation 264 357
Future income taxes (recovery) 672 (251)
Expenditures made on
asset retirements (28) (26)
----------------------------------------------------------------
Funds from operations 8,001 3,529
----------------------------------------------------------------
Changes in non-cash working capital
(note 12) (1,645) (278)
----------------------------------------------------------------
6,356 3,251
----------------------------------------------------------------
Financing Activities
Issuance of common shares, net
(note 8) 3,818 5,772
Bank loan (454) 5,088
Exercise of stock options 18 6
Repurchase of common shares (77) (547)
----------------------------------------------------------------
3,305 10,319
----------------------------------------------------------------
Investing Activities
Petroleum and natural
gas properties (10,566) (12,406)
Changes in non-cash working capital 868 (1,128)
----------------------------------------------------------------
(9,698) 13,534)
----------------------------------------------------------------
Change in cash (37) 36
Cash, beginning of the year 44 8
----------------------------------------------------------------
Cash, end of the year $ 7 $ 44
----------------------------------------------------------------
Supplemental Information
----------------------------------------------------------------
Cash interest paid $ 544 $ 308
----------------------------------------------------------------
-****-
See accompanying notes to financial statements.
IRONHORSE OIL & GAS INC.
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2008 and 2007
(Tabular amounts are expressed in thousands of dollars except share and per share numbers)
1. DESCRIPTION OF BUSINESS
Ironhorse Oil & Gas Inc. ("Ironhorse" or the "Company") is engaged in the exploration for and development and production of petroleum and natural gas reserves in western Canada.
2. SIGNIFICANT ACCOUNTING POLICIES AND BASIS OF PRESENTATION
The financial statements of the Company have been prepared by management in accordance with Canadian generally accepted accounting principles.
a) Petroleum and natural gas properties
Capitalized costs
The Company follows the full cost method of accounting, whereby all costs associated with the exploration for and development of petroleum and natural gas reserves are capitalized in a single Canadian cost centre. Such amounts include land acquisition costs, geological and geophysical expenditures, carrying charges of non-producing properties, costs of drilling productive and non-productive wells, site restoration and abandonment costs and administrative costs related to exploration and development activities.
Proceeds from the sale of properties are applied against capitalized costs and gains or losses are not recognized in the statement of income unless the depletion and depreciation rate would be changed by 20% or more.
Impairment test
The Company performs an impairment test whereby the carrying value of its petroleum and natural gas properties is compared at the end of each reporting period to an estimate of the undiscounted future net cash flow from the production of gross proved reserves plus the cost of unproved properties, net of impairments, excluded from depletion. Net cash flow is estimated using forecast prices, less estimated costs directly associated with the development, production and sale of reserves. Should the impairment test result in an excess of carrying value, the Company would then measure the amount of impairment by comparing the carrying amounts of property and equipment to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves and the carrying value of unproved properties, major development projects, net of impairments. A risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess is recorded as a permanent impairment. Undeveloped and unproved properties are also assessed periodically to determine whether impairment has occurred.
Depletion and depreciation
The capitalized costs of petroleum and natural gas properties plus future development costs, if any, are depleted and depreciated using the unit-of-production method based on the Company's interest in proved reserves of petroleum and natural gas calculated before royalties. Estimated proved reserves are based on reports prepared by independent engineering consultants. Petroleum substances are converted to volumes of energy equivalent barrels of oil at a conversion rate of six thousand cubic feet ("mcf") of natural gas to one barrel of crude oil.
Costs associated with the acquisition and evaluation of significant unproved properties where there is no commercial production are excluded from amounts subject to depletion and depreciation until such time as the properties are proved or become impaired.
b) Asset retirement obligation
The Company recognizes and measures the liabilities for obligations associated with the retirement of petroleum and natural gas properties when those obligations result from the acquisition, construction, development or normal operation of the asset. The obligation is measured at fair value and the related costs recorded as part of the carrying value of the related asset. Fair value is estimated using the present value of the estimated future cash costs to reclaim and abandon wells and facilities, using the Company's credit-adjusted risk free interest rate. In subsequent periods, the liability is adjusted for the change in present value and any changes in the amount or timing of the underlying future cash flows required for settlement of the obligation with a corresponding charge to property and equipment. The asset retirement costs included in petroleum and natural gas costs are depleted or amortized into income in accordance with the Company's policies pertaining to those assets.
c) Interests in joint ventures
Substantially all of the Company's petroleum and natural gas exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities.
d) Future income taxes
The Company uses the liability method for accounting for future income taxes. Under the liability method, future income tax assets and liabilities are determined based on "temporary differences" (differences between the accounting basis and the tax basis of the assets and liabilities), and are measured using the currently enacted tax rates and laws expected to apply when those temporary differences reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period when the change is substantially enacted. A valuation allowance is recorded against any future income tax assets if it is more likely than not that the asset will not be realized.
e) Flow-through shares
Resource expenditure deductions funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. To recognize the foregone tax benefits to the Company, the future income tax liability and the carrying value of the shares issued are adjusted by the effect of the tax benefits renounced to subscribers in the period when the corresponding exploration and development expenditures are renounced.
f) Stock-based compensation
The Company follows the fair value method to record the compensation expense for stock options granted under its stock option plan. Under this method, the Company estimates the fair value of stock options using the Black-Scholes option pricing model on the date of granting. Based on the value of the option granted, stock-based compensation expense and an offsetting credit to contributed surplus is recorded over the vesting period. When options are exercised, the amortized portion of the value of the option is transferred from the contributed surplus account to the share capital account.
At the discretion of the Board of Directors, the Company's stock option plan provides that option holders may take a cash settlement payment for the in-the-money value of the option on the exercise date. Should such a cash settlement payment be made to the option holder, the amortized portion of the original value of the option is reversed from the contributed surplus account to the extent of the cash settlement payment made to the option holder.
g) evenue recognition
Revenue from the production of petroleum and natural gas is recognized when deliveries of products are made to third parties.
h) Use of estimates
Management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reported period. The amounts recorded for depletion and depreciation of petroleum and natural gas properties and the provision for the asset retirement obligation and the ceiling test are based on estimates of proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. The fair value of stock options and the related stock-based compensation expense is based on estimates using the Black-Scholes option pricing model. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.
i) Net income per share
Diluted per share amounts are calculated using the treasury stock method. Diluted calculations reflect the incremental common shares that would be issued upon exercise of dilutive options, warrants and equivalents assuming the proceeds would be used to repurchase shares at average market prices for the period. Anti-dilutive items are not included in the calculation.
j) Financial instruments
The Company's financial assets and liabilities are classified and measured as follows:
- Cash and cash equivalents are classified as held for trading and are measured at fair value.
- Accounts receivable are classified as loans and receivables and are initially measured at fair value, and subsequently at amortized cost using the effective interest rate method, which approximates fair value.
- Accounts payable, accrued liabilities and bank loan payable are classified as other liabilities and are initially measured at fair value, and subsequently at amortized cost using the effective interest rate method, which approximates fair value.
- Gains and losses related to periodical revaluations are recorded in net income
The Company accounts for its physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items, in accordance with its expected purchase, sale or usage requirements, as executory contracts on an accrual basis rather than as financial instruments.
3. CHANGES IN ACCOUNTING POLICIES
a) Capital Disclosures
On January 1, 2008, the Company adopted the new CICA standards for Capital Disclosures which require disclosures about the Company's objectives, policies, and processes for managing capital. These disclosures include a description of what the Company manages as capital, the nature of externally imposed capital requirements, how the requirements are incorporated into the Company's management of capital, whether the requirements have been complied with, or consequences of non-compliance and an explanation of how the Company is meeting its objectives for managing capital. These disclosures are set forth in note 10.
b) Financial Instruments - Disclosures and Presentation
On January 1, 2008, the Company adopted the new CICA standards relating to "Financial Instruments - Disclosures" and "Financial Instruments - Presentation", which replaced the previous standard "Financial Instruments - Disclosure and Presentation". The new disclosure standard outlines the disclosure requirements for financial instruments and non-financial derivatives. The guidance prescribes an increased importance on risk disclosures associated with recognized and unrecognized financial instruments and how such risks are managed. Specifically, it requires disclosure of the significance of financial instruments for a company's financial position. In addition, the guidance outlines revised requirements for the disclosure of qualitative and quantitative information regarding exposure to risks arising from financial instruments. The new presentation standard requirements are relatively unchanged from the previous presentation requirements. These disclosures are set forth in note 11.
c) International Financial Reporting Standards ("IFRS")
In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed that the change over to IFRS from Canadian GAAP will be required for publicly accountable enterprises effective for the interim and annual financial statements relating to fiscal years beginning on or after January 1, 2011. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.
The Company is developing an IFRS conversion plan, which will include project structure governance, resourcing and training, analysis of key GAAP differences and a phase plan to assess accounting policies under IFRS as well as potential IFRS 1 ("First Time Adoption of IFRS") exemptions. The Company expects to complete its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting and business activities, such as financing and compensation arrangements, during 2009.
4. Petroleum and Natural Gas Properties
-***-
-------------------------------------
Cost Accumulated Net
depletion Book Value
depreciation
-------------------------------------
2007 $30,732 $5,815 $24,917
-------------------------------------
2008 $41,670 $11,299 $30,371
-------------------------------------
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During 2008, the Company capitalized $157 thousand (2007- $185 thousand) of general and administrative expenses. In calculating the depletion and depreciation provision for the year ended December 31, 2008, $2.2 million (December 31, 2007 - $2.2 million) of costs relating to the undeveloped land, seismic and other costs were excluded from costs subject to depletion and depreciation. Estimated future development costs of $8.6 million (December 31, 2007 - $7.6 million) were included in the calculation of depletion and depreciation for the year ended December 31, 2008.
In conducting the ceiling test as at December 31, 2008, the Company's estimated future cash flows exceeded the carrying value of the related petroleum and natural gas properties, after using certain assumptions pertaining to future commodity prices. Assumptions for crude oil and natural gas sales prices in Canadian dollars, which were used in the ceiling test, are consistent with the Company's December 31, 2008 reserve report as provided by GLJ Petroleum Consultants and are detailed below:
-***-
------------------------------------------------
Oil Gas
Light Oil at Edmonton AECO Spot
($Cdn/barrel) ($Cdn/mmbtu)
------------------------------------------------
2009 $68.61 $7.58
2010 78.94 7.94
2011 83.54 8.34
2012 90.92 8.70
2013 95.91 8.95
Thereafter $97.84 - 105.99 $9.14 - 9.95
------------------------------------------------
-****-
5. BANK LOAN
At December 31, 2008, the Company had a $14.5 million (2007 - $8 million) revolving production credit facility with a Canadian chartered bank, of which $6.4 million was drawn on the facility. Advances bear interest at the Bank's prime lending rate, plus 0.25% or at prevailing bankers' acceptance rate plus an applicable bank fee. The credit facility is secured by a general security agreement, demand debenture providing a first floating charge over all of the assets and a fixed charge over all the producing wells.
6. ASSET RETIREMENT OBLIGATIONS
-***-
2008 2007
Balance, beginning of the year $ 666 $ 323
Incurred in the year 367 315
Expenditures made on asset retirements (28) (26)
Accretion expense 29 54
$ 1,034 $ 666
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The Company's asset retirement obligations are based on the net ownership interests in wells and facilities. Management estimates the costs to abandon and reclaim the wells and facilities and the estimated time period during which these costs will be incurred in the future. These costs are expected to be incurred over the next 21 years with the majority of the costs being incurred between 2023 and 2026. The undiscounted amount of the estimated costs at December 31, 2008 was $3.1 million (2007 - $1.9 million) using an inflation rate of 1.5% (2007 -1.5%). The estimated costs have been discounted at a credit adjusted risk free rate 7.75% (2007 - 7.75%)
7. FUTURE INCOME TAXES
Future income taxes differs from the amount that would be computed by applying the basic combined federal and provincial statutory income tax rate of 30.3% (2007 - 33.9%) to income before taxes. The reasons for the differences are as follows:
-***-
2008 2007
Statutory tax rate 30.3% 33.9%
Anticipated tax expense (recovery) $ 683 $ (360)
Add (deduct)
Non-deductible stock-based compensation 61 122
Tax rate changes in future (72) (13)
Future income taxes (recovery) $ 672 $ (251)
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The components of future income tax liability (asset) are as follows:
-***-
2008 2007
Future Tax liabilities
Petroleum and natural gas properties $ 2,193 $ 1,483
Future Tax assets
Share issue costs (83) (20)
Non-capital losses (48) (67)
Asset retirement obligations (290) (203)
Net future income tax liability $ 1,772 $ 1,193
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8. SHARE CAPITAL
The Company has authorized an unlimited number of common shares and first preferred shares. The outstanding share capital is as follows:
a) Common shares
-***-
-------------------------------------------------------------------------------
NUMBER OF SHARES AMOUNT
-------------------------------------------------------------------------------
Balance, December 31, 2006 17,067,392 $ 14,094
Issue of common shares for cash 1,812,500 3,625
Issue of flow-through common shares 906,250 2,175
for cash
Options exercised 31,667 21
Shares repurchased under normal course (341,000) (344)
issuer bid
Tax effect of flow-through share - (663)
renouncements
Share issue costs, net of future income - (20)
taxes of $92
-------------------------------------------------------------------------------
Balance, December 31, 2007 19,476,809 18,888
Issue of common shares for cash 200,000 300
Issue of flow-through common shares 1,883,000 3,820
for cash
Options exercised 293,334 80
Shares repurchased under normal course (73,400) (83)
issuer bid
Transfer from contributed surplus - 47
Share issue costs, net of future income - (210)
taxes of $92
-------------------------------------------------------------------------------
Balance, December 31, 2008 21,779,743 $ 22,842
-------------------------------------------------------------------------------
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On January 31, 2007, the Company completed a non-brokered private placement of 906,250 common shares issued on a "flow-through" basis at a price of $2.40 per share and 1,812,500 common shares at a price of $2.00 per share for gross proceeds of $5.8 million. The Company has fulfilled it's obligation to incur $4.35 million of qualifying Canadian exploration expenditures.
On May 12, 2008 the Company completed a non-brokered private placement financing, to certain officers of the Company, for aggregate gross proceeds of $0.6 million comprised of 200,000 common shares at a price of $1.50 per share and 200,000 common shares issued on a "flow-through" basis at a price of $1.60 per share. The tax effect will be recorded in 2009 when the expenditures are renounced to the subscribers.
On October 23, 2008, the Company completed a brokered private placement of 1,683,000 common shares issued on a "flow-through" basis at a price of $2.08 per share for gross proceeds of $3.5 million. The Company is obligated to incur $3.5 million of qualifying Canadian exploration expenditures prior to December 31, 2009. The tax effect will be recorded in 2009 when the expenditures are renounced to the subscribers.
b) Normal Course Issuer Bid
On December 31, 2008, the Company reactivated its normal course issuer bid whereby it could acquire up to 1,493,459 common shares for cancellation. During the year, the Company acquired 73,400 common shares at an average carrying value of $1.13 per share. To date in 2009, the Company has acquired 92,700 common shares at an average price of $1.31 per share.
c) Options and Stock Based Compensation
The Company has a stock option plan under terms of which it will grant options to acquire common shares to certain officers, directors, employees and consultants. Under terms of the plan, options totaling up to 10% of the common shares outstanding from time to time are issuable, and no more than 5% of the outstanding options may be issued to any one person as defined by the plan.
The following tables summarize information about the Company's stock options outstanding:
-***-
----------------------------------------------------------------------
Number of options Weighted average
exercise price
----------------------------------------------------------------------
BALANCE, DECEMBER 31, 2006 1,651,666 $ 1.24
Granted 210,500 1.47
Exercised (31,667) (0.33)
Forfeited (222,999) (1.08)
----------------------------------------------------------------------
BALANCE, DECEMBER 31, 2007 1,607,500 1.26
Granted 1,266,500 1.26
Exercised (293,334) (0.27)
Exercised for cash (230,000) (0.48)
Forfeited (194,499) (1.94)
----------------------------------------------------------------------
BALANCE, DECEMBER 31, 2008 2,156,167 $ 1.41
----------------------------------------------------------------------
-****-
-***-
DECEMBER 31, 2008 December 31, 2007
EXERCISE OPTIONS AMOUNTS REMAINING Options Amounts Remaining
PRICE OUTSTANDING VESTED CONTRACTUAL Outstanding Vested Contractual
LIFE Life
(YEARS) (Years)
$0.23 - - - 300,000 300,000 1.0
0.37 100,000 100,000 0.1 200,000 200,000 1.1
0.38 83,000 83,000 1.1 178,334 118,888 2.1
1.01 541,500 - 4.9
1.28 64,167 22,503 3.9 105,500 - 4.9
1.30 235,000 16,667 4.1 50,000 - 5.0
1.40 170,000 - 4.2 - - -
1.50 170,000 - 4.3 - - -
1.60 180,000 - 4.4 - - -
1.68 410,000 410,000 1.5 515,000 343,334 2.5
2.00 15,000 5,000 3.4 15,000 - 4.4
2.07 5,000 5,000 1.9 5,000 3,333 2.9
2.86 12,500 8,334 2.4 12,500 4,167 3.4
2.95 170,000 115,004 2.4 226,166 75,390 3.4
2,156,167 765,508 3.4 1,607,500 1,045,112 1.7
-****-
The stock-based compensation expense is calculated based on the fair value of the stock options on the date of grant using the Black-Scholes option pricing model. The following assumptions were applied by the Company in this calculation for options granted in the period.
-***-
--------------------------------------------------------------------------------
2008 2007
--------------------------------------------------------------------------------
Weighted average fair value per option $ 0.51 $ 0.52
Dividend yield nil nil
Volatility 43% 29%
Risk-free rates 3.5% 4.0%
Expected life - years 5 5
--------------------------------------------------------------------------------
-****-
d) Per share amounts
The following table summarizes the shares used in calculating earnings per share:
-***-
---------------------------------------------------------------------
2008 2007
---------------------------------------------------------------------
Weighted average number of shares - basic 20,225,000 19,411,000
Effect of dilutive stock options 127,000 0
---------------------------------------------------------------------
Weighted average number of shares - diluted 20,352,000 19,411,000
---------------------------------------------------------------------
-****-
Options to purchase 2,029,167 (2007 - 1,607,500) common shares were not included in the calculation because they were anti-dilutive.
e) Contributed Surplus
-***-
2008 2007
OPENING BALANCE, JANUARY 1 $ 994 $ 854
Stock-based compensation expense 264 357
Reversal of amortized portion of the (62) (4)
option value on the exercise of options
for a cash payment
Normal course issuer bid purchase price (2) (202)
excess over carrying value
Transfer to share capital on exercise (40) (11)
of options
CLOSING BALANCE, DECEMBER 31 $ 1,154 $ 994
-****-
9. RELATED PARTY TRANSACTIONS
The Company is party to a management services contract with Grizzly Resources Ltd. ("Grizzly"), a company related by virtue of common management. Grizzly is also a significant joint operations partner in the Company's operating areas. These transactions are in the normal course of business and are recorded at the exchange amount which is the amount of consideration established and agreed to by the related parties.
The inter-company balances between the Company & Grizzly were as follows:
-***-
-------------------------------------------------------------
2008 2007
-------------------------------------------------------------
Accounts receivable $ 639 $ 0
Accounts payable $ 140 $ 525
-------------------------------------------------------------
-****-
The amounts outstanding at December 31, 2008 were settled in February 2009.
Management fees were paid as follows:
-***-
2008 2007
Production based fees expensed to G&A $ 729 $ 354
Capital based fees capitalized to property 156 185
and equipment
Total Management fees $ 885 $ 539
-****-
10. MANAGEMENT OF CAPITAL STRUCTURE
The Company actively manages its capital structure with the objective of maximizing shareholder returns by minimizing the cost of capital while at the same time maintaining its ability to execute the Company's future exploration and development program.
Ironhorse's capital structure includes shareholders' equity, bank debt and working capital. In managing its capital structure, the Company considers the following: future investment and acquisition opportunities; the current level of credit available from the Company's lender; the amount of credit that may be obtainable from the Company's lender as a result of changes in reserve values; the availability of other sources of debt; the sale of assets; adjustments to the current capital expenditures program; and issuance of new share equity. The Company's objective is to maintain a flexible capital structure that will allow it to execute its capital expenditures program, including exploration and development of its oil and gas properties and acquisition and disposition transactions which all carry varying amounts of risk. Ironhorse continually strives to balance the proportion of debt and equity in its capital structure to take into account the level of risk being incurred in its capital expenditures program. Ironhorse may from time to time, issue shares and adjust its spending to manage current and projected debt levels.
The methods used by the Company to monitor capital is based on the ratio of net debt to annualized funds from operations and also the ratio of net debt to the maximum amount of the Company's credit facility. The first net debt ratio is calculated as net debt, defined as outstanding debt plus or minus working capital, divided by annualized funds from operations which is calculated as the current quarter ended funds from operations times four. The second net debt ratio is calculated as net debt, defined as outstanding revolving bank loan plus or minus working capital, divided by the credit facility availability. Ironhorse's current strategy is to maintain a ratio of net debt to annualized funds from operations of no more than 2.0 to 1.0 and its ratio of net debt to credit facility availability at less than 90%. The ratios may temporarily increase at certain times as a result of capital expenditures, which are necessary to bring new reserves on production, and commodity prices being significantly lower than those used in the budget. The annual and updated budgets are based on current commodity prices. As at December 31, 2008, Ironhorse's ratio of net debt to annualized funds from operations was 1.11 to 1.0 (2007 - 2.70 to 1.0) which is well within the Company's optimal ratio despite lower commodity prices in the second half of 2008. The Company's ratio of net debt to credit facility availability was 47% (2007 - 99%), which was within the range established by the Company.
The Company's share capital is not subject to external restrictions but the Company does have financial covenants in regards to its credit facility. The credit facility requires the Company to maintain a ratio of "Funded Debt to Cash Flow", calculated on a historical rolling four quarter basis, equal to or less than 3:1 for purposes of this calculation cash flow is calculated as earnings before interest, taxes, and depletion. Funded Debt is defined as all short term and long-term interest bearing debt, capital leases and other obligations.
-***-
2008 2007
Current assets $ 1,828 $ 926
Current liabilities 8,617 8,909
Net debt 6,789 7,983
Annualized cash flow 6,100 2,952
NET DEBT TO ANNUALIZED CASH FLOW RATIO 1.11 2.70
Credit facility availability $ 14,500 $ 8,000
NET DEBT TO CREDIT FACILITY AVAILABILITY RATIO 0.47 0.99
-****-
11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company has identified the following risks which are significant to its operations:
a) Commodity price risk management
The Company produces petroleum and natural gas which have historically been subject to large fluctuations in price. Ironhorse has entered into several commodity price contracts to manage its exposure to price fluctuations. In 2008 these were comprised of a fixed price physical natural gas contract for the period April 1, 2008 to October 31, 2008 for 2000 GJ per day at $7.05 per GJ, as well as two costless collars physical natural gas contracts from November 1, 2008 to March 31, 2009. One contract is for 1,000 GJ per day based on a floor price of $7.75 per GJ and a ceiling price of $9.45 per GJ and the other contract is for 500 GJ per day based on a floor price of $8.00 per GJ and a ceiling price of $10.00 per GJ. As these are physical contracts they have not been accounted for at their underlying fair value. If the Company had closed these contracts on December 31, 2008 it would have resulted in a gain of $240,000. Assuming production averages 1,100 boe per day and is 90 percent gas weighted a $0.25 per mcf change in the gas price will result in approximately a $0.6 million change in revenue.
b) Credit risk
Credit risk is the potential financial loss to the Company if a customer or joint venture partner is unable to meet its contractual obligations and arises principally from the Company's accounts receivable with respect to the sale of petroleum and natural gas. The Company's petroleum and natural gas is marketed on behalf of the company by Grizzly under standard industry terms. In order to mitigate credit risk, Grizzly markets its petroleum and natural gas to established credit worthy purchasers.
At December 31, 2008 accounts receivable were $1.8 million, of which $1.1 million relates to accrued revenue for the month of December and $0.6 million is receivable from Grizzly. The remaining balance is made up of various smaller account balances. All amounts outstanding at December 31, 2008 between the Company and Grizzly were settled in February 2009.
c) Liquidity risk
Liquidity risk is the potential for the Company to have difficulty in meeting its obligations associated with financial liabilities as they become due. Ironhorse financial liabilities consist of accounts payable, financial instruments, and bank debt. All of the Company's financial liabilities have contractual maturities of less than one year and accounts payable are processed within normal payment terms. Ironhorse prepares an annual budget which is monitored and updated throughout the year. Occasionally the Company enters into fixed price contracts with respect the sale of a portion of its production to protect its cash flow from commodity price declines. The Company also mitigates liquidity risk by maintaining an insurance program to minimize its exposure to insurable losses.
d) Interest rate risk
The Company's bank lines bear interest at the bank prime rate plus 0.25 percent. Fluctuations in the prime rate will result in changes to the monthly interest expense. Assuming an average bank loan balance of $10 million, a change in the interest rate of 0.50 percent will result in a $50,000 change in the interest expense.
12. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
-***-
2008 2007
Changes in non-cash working capital:
Accounts receivable $ (939) $ (444)
Accounts payable and accrued liabilities 162 (962)
$ (777) $ (1,406)
Relating to:
Operations $ (1,645) $ (278)
Investing 868 (1,128)
$ (777) $ (1,406)
-****-
For further information, please contact:
Rob Solinger
VP Finance & CFO
(403) 355-3620
rsolinger@ihorse.ca
or visit our website at www.ihorse.ca.
"Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release."
Ironhorse Oil & Gas Inc. is a Calgary-based junior oil and natural gas production company trading on the TSX Venture Exchange under the symbol "IOG".
Forward Looking Statements
Statements throughout this release that are not historical facts may be considered to be "forward looking statements". These forward looking statements sometimes include words to the effect that management believes or expects a stated condition or result. All estimates and statements that describe the Company's objectives, goals, or future plans, including management's assessment of future plans and operations, drilling plans and timing thereof, expected production rates and additions and the expected levels of activities may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, volatility of commodity prices, imprecision of reserve estimates, environmental risks, competition from other producers, incorrect assessment of the value of acquisitions, failure to complete and/or realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and changes in the regulatory and taxation environment. As a consequence, the Company's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the ability of the Company to obtain equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manor; and field production rates and decline rates. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included elsewhere herein and in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Furthermore, the forward-looking statements contained in this release are made as at the date of this release.
Boe Conversion - Certain natural gas volumes have been converted to barrels of oil equivalent ("boe") whereby six thousand cubic feet (mcf) of natural gas is equal to one barrel (bbl) of oil. This conversion ratio is based on an energy equivalency conversion applicable at the burner tip and does not represent a value equivalency at the wellhead.
Source: Ironhorse Oil & Gas Inc. (TSX-V: IOG) http://www.ihorse.ca
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