ProspEx Announces 2010 First Quarter Results
(All amounts are in Canadian dollars, unless stated otherwise)
CALGARY, May 10 /CNW/ - ProspEx Resources Ltd. ("ProspEx" or the "Company") announces its 2010 first quarter results.
HIGHLIGHTS
- Production for the first quarter averaged 2,994 barrels of oil
equivalent ("boe") per day, a 21% increase compared to the fourth
quarter of 2009, as production from new horizontal wells in the Kakwa
area more than offset the disposition of production in West Central
Alberta in late December.
- ProspEx completed its pilot program to evaluate the use of horizontal
drilling with multi-stage fracturing technology at East Kakwa during
the first quarter. This program was very successful, and the Company
now has three horizontal wells on production, with initial rates from
each well ranging from 5 to 8 million cubic feet ("mmcf") per day.
- Capital expenditures for exploration and development were
$7.9 million during the first quarter of 2010. The Company drilled
two (1.2 net) horizontal wells in the quarter: one at East Kakwa and
one at Brazeau River.
- Cash flow before changes in non-cash working capital items for the
quarter was $5.3 million, an increase of 107% compared to the prior
quarter due to increases in production levels, improved commodity
prices and lower costs.
- Total net debt, excluding the fair value of commodity contracts,
associated future taxes and the current loss on ProspEx's office
sublease was $24.2 million at March 31, 2010. Subsequent to quarter
end, ProspEx's credit facility was renewed with a limit of
$40.0 million, compared to the previous limit of $33.0 million.
- ProspEx has hedges in place for the period April 1, 2010 to
October 31, 2010 for 7,000 Gigajoules ("GJ") per day of gas,
equivalent to approximately 40% of forecasted production. These
hedges are designed to ensure a minimum price of approximately
$5.00/GJ for the hedged volumes.
OPERATIONAL REVIEW
Capital Program
Capital expenditures for exploration and development (before acquisitions and dispositions) were $7.9 million during the first quarter of 2010. Capital spending was slightly less than previously forecast, due to the deferral of the Brazeau well tie-in due to the onset of spring breakup. ProspEx participated in two (1.2 net) wells in the first quarter, as described below.
As part of its pilot program to evaluate the use of horizontal drilling with multi-stage fracturing technology, ProspEx drilled its third horizontal well (50% ProspEx interest) at East Kakwa in the first quarter. In addition, fracture stimulation of the second East Kakwa horizontal well was completed in the first quarter. The Company now has three horizontal wells on production at East Kakwa, with initial rates of 5 to 8 mmcf per day. These wells span the full length of ProspEx's land position, and have demonstrated the commerciality of the horizontal drilling concept at East Kakwa. In addition to producing natural gas at high rates, these wells also produced 175 to 280 barrels per day of natural gas liquids initially, which enhances the economics in an environment of lower natural gas prices
In addition to its horizontal drilling in the Falher formation at East Kakwa, ProspEx has also commenced drilling on new lands purchased in 2009 in West Central Alberta. In the Brazeau River area, ProspEx drilled its first horizontal well (65% ProspEx working interest) targeting the Notikewin formation in the first quarter. At the conclusion of a nine day flow test this well was producing at a rate of 1.0 mmcf per day, which is at the lower end of ProspEx's expectations based on production from other wells in the area. However, the flow rate increased throughout the duration of the test, and the Company believes that longer term production will be required to understand the productivity of the well. Accordingly, ProspEx plans to tie the well into the local pipeline system after spring break up and monitor the production, which is expected to help guide future drilling plans in the area.
ProspEx is planning a capital budget of $30.0 million (net of Alberta Royalty Drilling Credits) for 2010, contingent on commodity prices. Capital spending for the period April 1 to December 31, 2010 is therefore expected to be approximately $22.0 million. The capital program planned for the remainder of the year includes approximately six horizontal wells, including the Company's first horizontal well in the Pembina area (targeting the Falher formation which is being drilled by ProspEx in East Kakwa), as well as follow-up horizontal drilling in East Kakwa, Brazeau River and Pembina, contingent on drilling results and an assessment of ongoing production performance.
Please be advised that the forecasts above with respect to capital spending may constitute a "financial outlook" as contemplated by National Instrument 51-102 ("NI 51-102") of the Canadian Securities Administrators entitled Disclosure Obligations. The purpose of such information is to forecast the anticipated capital spending and sources of funds of the Company for 2010.
Production
Production (boe/d) Q1 2010 Q4 2009 Q3 2009 Q2 2009 Q1 2009
-------------------------------------------------------------------------
West Central Alberta 1,030 1,280 1,289 1,635 2,099
Deep Basin 1,953 1,183 675 944 985
Southern Alberta 3 6 7 503 713
Other 8 8 7 7 10
-------------------------------------------------------------------------
Total 2,994 2,477 1,978 3,089 3,807
The first quarter production of 2,994 boe per day was an increase of 21% compared to fourth quarter of 2009 production of 2,477 boe per day, as production additions from the Company's horizontal wells at East Kakwa more than offset the 250 boe per day of production in the Garrington and Willesden Green areas that was sold in December, 2009.
In East Kakwa ProspEx's horizontal wells have exhibited sustained prolific production. The first well was brought on stream in early November, 2009 and produced at an average rate of 5.7 mmcf per day of raw gas and 200 barrels per day of liquids (approximately 650 boe per day net to ProspEx's 60% working interest) in March, after approximately four months on stream.
ProspEx's second horizontal well came on production in early February, 2010, and averaged 7.7 mmcf per day of raw gas and 270 barrels per day of liquids in March (approximately 880 boe per day net to ProspEx's 60% working interest). The third horizontal came on stream in early March at an initial rate of 4.8 mmcf per day of raw gas and 170 barrels per day of liquids (460 boe per day net to ProspEx).
Prolific production performance from the new East Kakwa horizontal wells caused a temporary curtailment in production from the Company's five vertical wells during the first quarter, due to higher operating pressures in the area pipeline system. Modifications to this system were completed in mid-March and the vertical wells are now producing at full capacity.
With the three East Kakwa wells on stream, the Company estimates that total corporate production in March, 2010 was approximately 3,400 boe per day. ProspEx continues to monitor natural gas prices and may elect to curtail production in the event of further deterioration in summer prices. Assuming no production curtailments, the Company is maintaining its previous guidance of annual average production for 2010 in the 3,300 to 3,500 boe per day range, with production in late 2010 of approximately 4,000 boe per day. As production at the start of 2010 was approximately 2,700 boe per day, the forecasted 4,000 boe per day exit rate equates to almost 50% production growth over the year.
Guidance regarding production may constitute a "financial outlook" as contemplated by NI 51-102. The purpose of such guidance is to forecast the anticipated production for the Company for 2010.
Financial
Total net debt (excluding the fair value of commodity contracts, associated future taxes and the current loss on sublease) at March 31, 2010 was $24.2 million which is equivalent to 1.2 years net debt to trailing cash flow annualized. Subsequent to quarter end, ProspEx's credit facility was renewed with a limit of $40.0 million, compared to the previous limit of $33.0 million. This renewed facility provides the Company with financial flexibility and certainty of credit financing over the next year. The next scheduled review date of this facility is May 31, 2011.
ProspEx has historically followed a policy of hedging up to 50% of the Company's forecasted production up to a year in advance, typically using costless collars, swaps or puts. ProspEx has hedges in place for the period April 1, 2010 to October 31, 2010 for 7,000 GJ per day of gas production, equivalent to approximately 40% of forecasted production. These hedges are designed to provide a minimum price of approximately $5.00/GJ for the hedged volumes. Details of the individual hedges are provided in the Company's first quarter Management Discussion and Analysis. Although forward prices for natural gas over the summer of 2010 remain weak, these hedges should offer a degree of protection from lower natural gas prices over the summer.
Reader's Advisory
ProspEx is a Calgary based junior oil and gas company focused on exploration for natural gas in the Western Canadian Sedimentary Basin.
Certain information contained in this press release constitutes forward-looking information or statements including, without limitation, information and statements respecting: anticipated cash flow, capital expenditures, production forecasts, production additions and deletions, reserves and resources additions and deletions, additions to and deletions from the Company's historical and future capital programs, acquisitions or dispositions, operating expenses, G&A, royalties, expected timing of the tie-in of wells, expected timing of the receipt of regulatory approvals and expected timing of the completion of facilities projects.
Statements relating to "reserves" and "resources" are forward-looking information as they involve the implied assessment, based on certain estimates and assumptions that, among others, the reserves and resources described exist in the quantities predicted or estimated.
Forward-looking information and statements are often, but not always, identified by the use of words such as "anticipate", "seek", "believe", "expect", "hope", "plan", "intend", "forecast", "target", "project", "guidance", "may", "might", "will", "should", "could", "estimate", "predict" or similar words or expressions suggesting future outcomes or language suggesting an outlook. By their very nature, forward-looking information and statements involve inherent risks and uncertainties, both general and specific, and risks that predictions, forecasts, projections and other forward-looking information and statements will not be achieved. We caution readers not to place undue reliance on these statements as a number of important factors could cause the actual results to vary materially from the forward-looking information or statements. These factors include, but are not limited to: the volatility of oil and gas prices; production and development costs; capital expenditures; the imprecision of reserve and resource estimates and estimates of recoverable quantities of oil, natural gas and liquids; the Company's ability to replace and expand oil and gas reserves; environmental claims and liabilities; incorrect assessments of value when making acquisitions or dispositions; increases in debt service charges; the loss of key personnel; the marketability of production; defaults by third party operators; unforeseen title defects; fluctuations in foreign currency and exchange rates; inadequate insurance coverage; compliance with environmental laws and regulations; changes in tax and royalty laws; the Company's ability to access external sources of debt and equity capital; and the Company's ability to obtain equipment in a timely manner to carry out development activities. Further information regarding these factors may be found under the headings "Description of the Business - Risk Factors Relating to Our Business" and "Industry Conditions" in the Company's most recent Annual Information Form, under the heading "Operational and Other Business Risks" in the Company's Management's Discussion and Analysis for the year ended December 31, 2009, and in the Company's most recent consolidated financial statements, management information circular, quarterly reports, material change reports and news releases available under the Company's profile on SEDAR (www.sedar.com). Readers are cautioned that the foregoing list of factors that may affect future results is not exhaustive. When relying on our forward-looking statements to make decisions with respect to the Company, investors and others should also carefully consider information set forth in the section "Forward-Looking Information" of the Company's most recent Annual Information Form respecting the assumptions upon which the Company bases certain forward-looking information and the uncertainties inherent in such assumptions.
The Company does not assume responsibility for the accuracy and completeness of the forward-looking information or statements and such information and statements should not be taken as guarantees of future outcomes. Subject to applicable securities laws, the Company does not undertake any obligation to revise these forward-looking information or statements to reflect subsequent events or circumstances. Furthermore, the forward-looking information contained in this press release are made as of the date of this document and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by applicable law. The forward-looking information and statements contained in this press release are expressly qualified by this cautionary statement.
For the purposes of this press release, boe has been calculated on the basis of six thousand cubic feet of gas to one barrel of oil. The term boe may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
"Operating netbacks" are calculated by subtracting transportation costs, royalties and operating costs from the average price received during the period.
"Total net debt" is calculated by adding long-term debt less working capital (or plus working capital deficiency), excluding fair value of commodity contracts and associated future tax assets (liabilities) and current loss on sublease.
ProspEx Resources Ltd.
Consolidated Highlights
For the period ended
Three Three
months months
ended ended
March 31, March 31,
(unaudited) 2010 2009
-------------------------------------------------------------------------
FINANCIAL ($000's)
Oil and gas revenue 10,526 12,765
Net earnings (loss) 1,908 (2,225)
Cash flow(1) 5,252 5,720
Total assets 160,007 195,822
Total net debt(2) 24,237 49,267
Net earnings (loss) per share ($ per share)
Basic 0.03 (0.04)
Diluted 0.03 (0.04)
Cash flow per share ($ per share)(1)
Basic 0.09 0.10
Diluted 0.09 0.10
Weighted average common shares (000's)
Basic 57,385 57,385
Diluted 58,108 57,385
PRODUCTION VOLUMES
Natural gas (mcf/d) 14,288 17,561
Natural gas liquids (bbls/d) 583 811
Oil (bbls/d) 29 69
-------------------------
Total (boe/d) 2,994 3,807
SALES PRICES
Natural gas ($/mcf) 5.73 6.20
Natural gas liquids ($/bbl) 56.10 36.05
Oil ($/bbl) 83.22 53.32
-------------------------
Total ($/boe) 39.07 37.25
OPERATING NETBACKS ($/boe)
Price 39.07 37.25
Royalties (5.85) (7.37)
Operating costs (7.97) (7.16)
Transportation (1.55) (1.04)
-------------------------
Total 23.70 21.68
CAPITAL ($000's)
Drilling and completions 5,219 3,586
Facilities 1,272 886
Land and lease 694 321
Seismic 43 50
Capitalized general and administrative 630 798
-------------------------
Total exploration & development 7,858 5,641
Property acquisitions (disposition) 12 (2,078)
Other capital assets - 3
-------------------------
Total 7,870 3,566
(1) Cash flow is defined as cash flow from operations before changes in
operating non-cash working capital.
(2) Total net debt is defined as long term debt less working capital (or
plus working capital deficiency), excluding fair value of commodity
contracts and associated future tax assets (liabilities) and current
loss on sublease.
Cash flow, cash flow per share (basic and diluted) and total net debt
do not have standardized measures prescribed by Canadian generally
accepted accounting principles and therefore may not be comparable
with calculation measures for other issuers.
MANAGEMENT DISCUSSION & ANALYSIS
Management's Discussion and Analysis ("MD&A") is management's assessment of the financial and operating results of ProspEx Resources Ltd. ("ProspEx" or the "Company") as well as a prospective view of the Company's activities. The MD&A is for the three months ended March 31, 2010, and was prepared as at May 10, 2010. The MD&A should be read in conjunction with the audited consolidated financial statements and MD&A for the year ended December 31, 2009 including the notes related thereto and the consolidated financial statements for the three months ended March 31, 2010 together with the notes related thereto. The reader should be aware that historical results are not necessarily indicative of future performance.
RESULTS OF OPERATIONS
The first quarter of 2010 was highlighted by the successful implementation of a new strategy of developing conventional natural gas properties utilizing horizontal wells with multi-stage fracturing technology. Two new horizontal wells commenced production in the first quarter of 2010, increasing production by 21% to 2,994 barrels of oil equivalent ("boe") per day from the 2,477 boe per day reported in the fourth quarter of 2009, despite the disposition of 250 boe per day in late December, 2009.
Capital expenditures for the first quarter of 2010 were highlighted by the drilling of two (1.2 net) wells, one in East Kakwa and one in the Brazeau area. This resulted in $7.9 million in capital expenditures for the quarter and the successful extension of the East Kakwa trend on to the Company's lands to the north.
Cash flow before changes in non-cash working capital items was $5.3 million in the first quarter, a decrease of 8% compared to the first quarter of 2009 due to lower production volumes. Compared to the fourth quarter of 2009, cash flow before changes in non-cash working capital items was up 107% due to production and price increases.
Total net debt, excluding the fair value of commodity contracts, associated future taxes and the current loss on sublease was $24.2 million which is equivalent to 73% of the limit on the Company's $33.0 million credit facility as of March 31, 2010. Subsequent to the quarter end the Company completed its annual credit review and increased its credit facility to $40.0 million.
Business environment
During the quarter, natural gas prices deteriorated as concerns over supply and demand fundamentals continue to haunt North American natural gas markets. North American natural gas markets faced continual pressure due to high storage levels that reflect the impact of increased domestic United States production from the horizontal drilling of unconventional shale plays.
As in 2009, capital preservation and careful allocation will be required in 2010. Capital spending will be targeted at securing new opportunities to advance the Company's strategy, and to testing these opportunities. This activity is expected to be oriented towards increasing the opportunity set available to the Company as the business conditions improve.
Revenue
Three Three
months months
ended ended
March 31, March 31,
($000's) 2010 2009
-------------------------
Natural gas $ 7,457 $ 8,485
Realized (loss) gain on financial instruments (95) 1,316
-------------------------
Total natural gas 7,362 9,801
Oil 218 330
Natural gas liquids 2,946 2,634
-------------------------
Oil and gas revenue 10,526 12,765
Unrealized financial instrument gain (loss) 2,196 (828)
-------------------------
Total revenue $ 12,722 $ 11,937
-------------------------
First quarter oil and gas revenue decreased $2.2 million or 18% to $10.5 million in 2010 from $12.8 million in the first quarter of 2009, as a result of the realized gain on financial instruments in the first quarter of 2009 combined with lower production volumes in 2010. First quarter 2010 total revenue of $12.7 million increased $0.8 million or 7% from $11.9 million in the same period of 2009 due to $2.2 million in unrealized financial instrument gains reported in 2010.
Production
Three Three
months months
ended ended
March 31, March 31,
2010 2009
-------------------------
Area (boe/d)
------------
Deep Basin 1,953 985
West Central Alberta 1,030 2,099
Southern Alberta 3 713
Other Areas 8 10
-------------------------
2,994 3,807
-------------------------
Product
-------
Natural gas (mcf/d) 14,288 17,561
Natural gas liquids (bbls/d) 583 811
Oil (bbls/d) 29 69
-------------------------
Total (boe/d) 2,994 3,807
-------------------------
First quarter 2010 production of 2,994 boe per day was down from the 3,807 boe per day recorded in the first quarter of 2009, due to natural declines and asset dispositions in Southern Alberta and West Central Alberta. The increase in Deep Basin production is due to a successful horizontal drilling program in the Kakwa area.
Production in the first quarter of 2010 increased by 517 boe per day or 21% to 2,994 boe per day from the 2,477 boe per day reported in the fourth quarter of 2009 as production increases due to successful drilling at Kakwa more than offset an asset disposition in the West Central area. Production for the month of March is estimated to have been approximately 3,400 boe per day.
Commodity Pricing
Three Three
months months
ended ended
March 31, March 31,
ProspEx Average Prices 2010 2009
-------------------------
Natural gas ($/mcf)
Sales price $ 5.80 $ 5.37
Realized (loss) gain on financial instrument (0.07) 0.83
-------------------------
5.73 6.20
Oil ($/bbl) 83.22 53.32
NGL ($/bbl) 56.10 36.05
-------------------------
Average realized price ($/boe) 39.07 37.25
Unrealized gain (loss) on
financial instrument ($/boe) 8.15 (2.42)
-------------------------
Total average price ($/boe) $ 47.22 $ 34.83
-------------------------
Three Three
months months
ended ended
March 31, March 31,
Benchmark pricing 2010 2009
-------------------------
AECO C Spot ($/mcf) $ 4.95 $ 4.92
Edmonton Par - light oil ($/bbl) $ 80.11 $ 49.66
-------------------------
Average natural gas sales prices increased 8% to $5.80 per thousand cubic feet ("mcf") in the first quarter of 2010, compared to $5.37 per mcf in the first quarter of 2009, following the trend of the AECO C daily spot price for natural gas. The Company's realized natural gas prices are higher than the benchmark due to the high heat content of the Company's liquids rich natural gas production. The Company's risk management program resulted in a gain of $0.83 per mcf in the first quarter of 2009 which led to the higher overall realized price in that quarter.
Oil prices received for the first quarter of 2010 were $83.22 per barrel ("bbl"). This is a 56% increase from the $53.32 per bbl received in the first quarter of 2009, consistent with the increase in benchmark pricing. The price realized for natural gas liquids ("NGLs") in the first quarter of 2010 was $56.10 per bbl, an increase of 56% from $36.05 per bbl in the first quarter of 2009. Overall oil and NGL prices have increased as the world wide economy has begun to recover.
Financial Instruments
For the quarter ended March 31, 2010, the Company's risk management program resulted in a net realized loss of $0.1 million, compared to a $1.3 million net realized gain for the same period in 2009. The slight loss in realized financial instruments for the first quarter is due to the premiums paid for put contracts.
The impact of the changes in the fair values of open financial instruments during the quarter ended March 31, 2010 was an unrealized gain of $2.2 million. This compares to an unrealized loss of $0.8 million for the first quarter of 2009. The unrealized gain reported in the current quarter is a result of the decline in the outlook of forward prices for natural gas.
The financial instruments open as of March 31, 2010 are described below:
Amount
Type (GJ/day) Term Price ($/GJ at AECO) Type
---- -------- ---- -------------------- ----
Fixed 1,000 Apr. 1 - Oct. 31, 2010 $5.18 Financial
Fixed 1,000 Apr. 1 - Oct. 31, 2010 $5.385 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $5.00 - $6.16 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $5.00 - $5.90 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $4.90 - $5.63 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $5.00 - $5.95 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $4.75 - $5.86 Financial
Royalty Expenses
Three Three
months months
ended ended
March 31, March 31,
($000's) 2010 2009
-------------------------
Crown $ 1,267 $ 2,015
Freehold and gross overriding 310 511
-------------------------
Total royalties $ 1,577 $ 2,526
-------------------------
$ per boe $ 5.85 $ 7.37
As a percentage of oil and gas revenue 15% 20%
-------------------------
In the first quarter of 2010, royalties totaled $1.6 million or 15% of revenue compared to last year's $2.5 million or 20% of revenue. Crown royalty payments decreased as a result of the Company's ability to take advantage of the Alberta Government's New Well Royalty Reduction incentive program enabling the new Kakwa wells to pay crown royalties at a rate of 5% in the first quarter of 2010. The reduction in freehold royalties is due to the disposition of the Medallion property, where a significant portion of the royalties paid were freehold royalties.
ProspEx is required to pay the Province of Alberta and other royalty owners for the right to produce minerals owned by them. Such royalty payments are subject to change and any changes may have an adverse impact on the profitability of a project. On March 11, 2010, the Government of Alberta announced additional amendments to the new oil and gas royalty framework which are to come into effect on January 1, 2011. Under the most recent amendments, the maximum royalty rate for natural gas is to be reduced from 50% to 36% and the maximum royalty rate for conventional oil wells is to be reduced from 50% to 40%. In addition, according to the announced amendments, the New Well Incentive Program is to become a permanent feature to the new oil and gas royalty framework. Further refinements to the amendments are anticipated to be announced by the Government of Alberta by May 31, 2010 including, without limitation, the royalty curves that are to be utilized to determine the applicable royalty rates.
Operating Costs
Three Three
months months
ended ended
March 31, March 31,
2010 2009
-------------------------
Operating costs ($000's) $ 2,146 $ 2,453
Operating costs ($/boe) $ 7.97 $ 7.16
-------------------------
Operating costs for the first quarter of 2010 were $2.1 million or $7.97 per boe, compared to $2.5 million or $7.16 per boe in the first quarter of 2009. Overall operating costs are down $0.3 million or 13% from the same period of 2009 due to the disposition of assets in Southern and West Central Alberta in 2009. On a per boe basis operating costs are up 11% from $7.16 per boe in 2009 to $7.97 per boe in the first quarter of 2010. The Company's unit operating costs during the first quarter of 2009 were lower than during the first quarter of 2010, due to the reversal of previously accrued processing fees in the first quarter of 2009.
Transportation Expenses
Three Three
months months
ended ended
March 31, March 31,
2010 2009
-------------------------
Transportation expenses ($000's) $ 417 $ 358
Transportation expenses ($/boe) $ 1.55 $ 1.04
-------------------------
Transportation expense per boe for the first quarter increased $0.51 per boe from the comparable period of 2009. This is due to the disposition of assets with lower transportation costs in West Central and Southern Alberta, and to increases in production in the higher cost Deep Basin area.
General and Administrative Expenses
Three Three
months months
ended ended
March 31, March 31,
($000's) 2010 2009
-------------------------
Gross general and administrative $ 1,600 $ 1,948
Recoveries (230) (245)
Capitalized expenses (630) (798)
-------------------------
Net general and administrative expenses $ 740 $ 905
-------------------------
Net general and administrative expenses ($/boe) $ 2.75 $ 2.64
-------------------------
Gross general and administrative costs were down $0.3 million compared to the same period in 2009. This is due to lower personnel costs achieved through staff reductions in 2009. Net general and administrative costs per boe did not change significantly.
Interest and Bank Charges
Interest and bank charges of $0.2 million in the first quarter were lower compared to the prior year amount of $0.3 million. This reduction is due to the lower debt levels in the first quarter of 2010, compared to the same period of 2009.
Depletion, Depreciation and Accretion
Three Three
months months
ended ended
March 31, March 31,
2010 2009
-------------------------
Depletion, depreciation and accretion ($000's) $ 4,836 $ 8,741
Depletion, depreciation and accretion ($/boe) $ 17.95 $ 25.51
-------------------------
Depletion, depreciation and accretion expense per boe in the first quarter of 2010 was $17.95 per boe, a 30% decrease from the first quarter 2009 rate of $25.51 per boe. In the fourth quarter of 2009 the depletion rate dropped to $18.29 per boe due to the increase in reserves related to drilling in the Kakwa area. First quarter 2010 drilling resulted in further reserve additions and a corresponding decrease in the depletion rate.
Income Taxes
In the first quarter of 2010, the Company's future income tax increased to an expense of $0.8 million compared to a future income tax reduction of $1.2 million in the same period in 2009. This increase in future income tax expense is a result of an increase in the overall net income before income taxes compared to the prior period.
Estimated tax pools as at March 31:
($000's) 2010 2009
-------------------------------------------------------------------------
Canadian development expense $ 40,475 $ 35,402
Canadian exploration expense 37,618 32,833
Canadian oil & gas property expense 16,363 36,474
Undepreciated capital cost 28,557 43,049
Other 4,112 4,645
-------------------------------------------------------------------------
$ 127,125 $ 152,403
-------------------------------------------------------------------------
Net Earnings and Cash Flow
The Company reported net earnings of $1.9 million, versus a $2.2 million net loss in the same period of 2009. Lower production and the absence of a realized gain in the first quarter of 2010 resulted in reduced oil and gas revenue. This was offset by an increase of $3.0 million in unrealized gains relating to financial instruments, a $3.9 million reduction in depletion, depreciation and accretion expense, reduced royalties and lower total operating costs compared to those seen in the first quarter of 2009. The net effect was a $4.1 million increase in net earnings in the first quarter of 2010 relative to the same period of 2009.
The Company's cash flow for the first quarter of 2010 was affected by lower production, offset by lower operating costs. First quarter 2010 cash flow before changes in non-cash working capital was $5.3 million, a decrease of 8% or $0.5 million from the same period of 2009.
Capital Expenditures
Net capital expenditures were $7.9 million during the first quarter of 2010, compared to net expenditures of $3.6 million in the first quarter of 2009. Details of these expenditures for the period ended March 31 were as follows:
($000's) 2010 2009
-------------------------------------------------------------------------
Drilling and completions $ 5,219 $ 3,586
Facilities 1,272 886
Land and lease 694 321
Seismic 43 50
Capitalized general and administrative 630 798
-------------------------------------------------------------------------
Exploration & development capital expenditures 7,858 5,641
Net property acquisitions (dispositions) 12 (2,078)
Other capital expenditures - 3
-------------------------------------------------------------------------
Total net capital expenditures $ 7,870 $ 3,566
-------------------------------------------------------------------------
For the first quarter of 2010, the Company participated in drilling two (1.2 net) horizontal wells, one in East Kakwa and one in Brazeau.
Liquidity & Capital Resources
At March 31, 2010, ProspEx had the following financial resources available to fund its capital expenditure program.
($000's)
-------------------------------------------------------------------------
Working capital deficiency, excluding fair value
of commodity contracts, associated future tax
liabilities and current loss on sublease $ (2,881)
Long-term debt (21,356)
Bank facilities available 33,000
-------------------------------------------------------------------------
Total capital resources $ 8,763
-------------------------------------------------------------------------
-------------------------------------------------------------------------
ProspEx expects that it will be able to fund its 2010 capital program from operating cash flow and the capital resources noted above.
As at March 31, 2010 the Company's ratio of total net debt to annualized cash flow was 1.2 to 1.0, which is in line with the Company's guidelines on capital management strategy.
Bank Debt
At March 31, 2010 the Company had a $33.0 million credit facility with a major Canadian bank. The facility revolves for 364 day periods, at which time the Company can request approval from the lender for an extension for an additional 364 day period or convert the outstanding bank indebtedness to a one year term loan. The amount of the facility is subject to a borrowing base test performed on a periodic basis by the lenders, based primarily on reserves and using commodity prices estimated by the lenders, as well as other factors. A decrease in the borrowing base could result in a reduction of the credit facility which may require a repayment to the lenders within sixty days of receiving notice of the new borrowing base. The credit facility provides that advances may be made by way of prime rate loans, guaranteed notes (bankers' acceptances) and letters of credit. The credit facility is tested quarterly, in arrears, and bears interest based on a sliding scale. The interest rate varies depending on the Company's debt to cash flow ratio determined quarterly on a grid system, with the grid ranging from debt to cash flow ranges of lower than 1.0:1.0 to greater than 3.0:1.0.
The facility is secured by a general security agreement conveying a first floating charge over all real and personal property and after acquired assets. The Company is required to meet certain financial based covenants under the terms of this facility. As at March 31, 2010, the Company is in compliance with all covenants in accordance with the terms of the credit facility.
Subsequent to the quarter the Company completed its annual credit review resulting in an increase to its credit facility to $40.0 million. The next scheduled review date of the facility is May 31, 2011.
Share Capital
As at March 31, 2010, ProspEx had 57,385,162 common shares (2009 - 57,385,162), no warrants (2009 - 2,016,269), and 5,175,834 options (2009 - 5,102,877) issued and outstanding. Each option, upon exercise, entitles the holder to one common share.
As at May 10, 2010 ProspEx had 57,385,162 common shares, no warrants, and 5,175,834 options issued and outstanding.
Contractual Obligations
The Company has committed to certain payments as follows:
Payments due There-
($000's) 2010 2011 2012 2013 2014 after Total
-------------------------------------------------------------------------
Long-term debt $ - $21,356 $ - $ - $ - $ - $21,356
Building lease 702 1,051 1,356 1,433 358 - 4,900
Processing fees 284 63 - - - - 347
Transportation 334 443 147 - - - 924
Other 3 - - - - - 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total $1,323 $22,913 $1,503 $1,433 $ 358 $ - $27,530
-------------------------------------------------------------------------
Subsequent events
Subsequent to the quarter end, the Company amended its agreement to process and gather raw gas at the Musreau Gas Plant. This amendment extends the Company's firm commitment for capacity at the plant to February 28, 2015. The total obligation is estimated to be $2.7 million over the life of this agreement.
The Company completed the annual renewal of its credit facility with a major Canadian bank in April 2010. The facility was increased at this time to a total of $40.0 million and is not scheduled to be reviewed again until May 31, 2011.
Off-Balance Sheet Arrangements
The Company has not entered into any off-Balance Sheet transactions other than previously discussed.
Summary of Quarterly Results
The following table summarizes the quarterly operating statistics of the Company.
Q1 Q4 Q3 Q2
2010 2009 2009 2009
-------------------------------------------------------------------------
Average Daily Production
Natural Gas (mcf/d) 14,288 11,327 8,906 14,382
NGL (bbls/d) 583 557 456 645
Oil (bbls/d) 29 32 37 47
-----------------------------------------
Total (boe/d) 2,994 2,477 1,978 3,089
-----------------------------------------
Operating Netbacks ($/boe)
Price $ 39.07 35.49 27.61 26.22
Royalties (5.85) (5.15) (1.21) (1.21)
Operating costs (7.97) (8.72) (8.37) (9.30)
Transportation (1.55) (1.21) (1.12) (0.93)
-----------------------------------------
Total $ 23.70 20.41 16.91 14.78
-----------------------------------------
E&D Capital Spending ($000's) $ 7,858 3,988 6,438 1,619
Selected Financial Results
($000's, except per share amounts)
Oil and gas revenue $ 10,526 8,088 5,023 7,370
Unrealized financial
instrument gain (loss) 2,196 (2) (401) 310
Net earnings (loss) 1,908 (1,231) (3,082) (3,899)
Basic per share $ 0.03 (0.02) (0.05) (0.07)
Diluted per share $ 0.03 (0.02) (0.05) (0.07)
-------------------------------------------------------------------------
Q1 Q4 Q3 Q2
2009 2008 2008 2008
-------------------------------------------------------------------------
Average Daily Production
Natural Gas (mcf/d) 17,561 16,868 18,379 19,957
NGL (bbls/d) 811 719 722 851
Oil (bbls/d) 69 57 65 108
-----------------------------------------
Total (boe/d) 3,807 3,587 3,850 4,285
-----------------------------------------
Operating Netbacks ($/boe)
Price 37.25 45.59 55.65 63.00
Royalties (7.37) (8.18) (12.98) (11.97)
Operating costs (7.16) (4.58) (7.76) (8.39)
Transportation (1.04) (1.00) (0.91) (1.00)
-----------------------------------------
Total 21.68 31.83 34.00 41.64
-----------------------------------------
E&D Capital Spending ($000's) 5,641 12,797 12,693 8,615
Selected Financial Results
($000's, except per share amounts)
Oil and gas revenue 12,765 15,046 19,714 24,567
Unrealized financial
instrument gain (loss) (828) (363) 8,277 (2,781)
Net earnings (loss) (2,225) 487 6,923 2,261
Basic per share (0.04) 0.01 0.12 0.04
Diluted per share (0.04) 0.01 0.12 0.04
-------------------------------------------------------------------------
(1) Price excludes unrealized financial instrument gain or loss.
Quarter to quarter results are influenced by many factors. The three main drivers are capital spending, production and commodity prices.
Capital spending is typically more heavily weighted to the winter drilling months, and therefore the fourth and first quarters of the year usually represent approximately 60% of the exploration and development budgets. The second quarter of each year usually has minimal capital spending, reflecting surface access restrictions due to spring break up conditions. Production additions typically lag capital spending by one or two quarters, resulting in production peaks in the second quarter of each year.
As previously mentioned, production is a key driver of overall quarterly results. Production is not only influenced by additions as a result of capital programs and subtractions as a result of dispositions, but also by natural declines as production from existing wells diminishes over time. With respect to the Company's overall quarterly production profile, production tends to peak in the second quarter of each year, reflecting new additions from the winter drilling programs, and the subsequent quarters reflect declining production as natural decline rates come into play. In 2009 this trend was further complicated by disposition activity and production curtailments due to low prices.
World-wide commodity price environments have a significant influence on the overall Company's quarterly results. The Company is a price-taker in the oil & gas industry and as a result, world prices drive Company revenues. Natural gas prices are currently low, driven by high natural gas storage inventories, strong domestic production levels in the United States, and reduced demand for natural gas as a result of the global economic downturn. In the face of this uncertainty, the Company has adopted a conservative approach by restricting exploration and development capital spending and as a consequence total net oil and gas revenues may not follow traditional quarterly cyclical trends in 2010.
NEW ACCOUNTING PRONOUNCEMENTS
Accounting Standards Adopted and Recent Pronouncements
Financial Instruments - Disclosures
In May 2009 amendments were made to Section 3862, Financial Instruments - Disclosures to include additional disclosures about the fair value of financial instruments and the liquidity risk associated with financial instruments. These amendments require a three level hierarchy that reflects the significance of the inputs used in making the fair value measurements. Refer to note 4 for the enhanced disclosures.
International Reporting Standards
On January 1, 2011 International Financial Reporting Standards ("IFRS") will replace Canadian Generally Accepted Accounting Principles for Canadian publicly accountable enterprises. Quarterly and annual results will be reported in accordance with IFRS beginning in 2011, with the restatement of 2010 amounts for comparative purposes. A project team has been formed to lead the conversion project and has engaged in IFRS educational programs. The Company has and will continue to involve the external auditors throughout the process and maintain regular progress reporting to the Audit Committee of the Board of Directors.
The Company's IFRS transition project includes four key phases:
- project planning and scoping
- draft policy and impact assessment
- implementation and parallel reporting
- ongoing monitoring and IFRS policy updates
Project planning and scoping
The Company has completed the project planning and scoping phase of the project. Project planning entailed developing a project plan, appointing internal staff and allocating resources. Scoping consisted of identifying and performing a high level impact analysis to identify areas that may be affected by the transition. There are several significant accounting policy changes anticipated on adoption of IFRS. These include petroleum and natural gas assets ("P&NG Assets"), asset retirement obligation, business combinations and future income taxes. Also, future changes in IFRS prior to adoption may result in other accounting policy changes which could significantly impact the financial statements.
The key differences with respect to P&NG Assets have been identified and a high level preliminary analysis has been performed. ProspEx currently follows the full cost accounting guideline under Canadian GAAP resulting in the accumulation of all costs directly associated with the acquisition of, exploration for and development of oil and gas assets in one cost center. Costs are depleted using the unit of production method based on proved reserves. At transition to IFRS, new accounting policies must be adopted for exploration and evaluation costs and development costs.
- Exploration and evaluation costs are those expenditures for a project
for which technical feasibility and commercial viability have not
been determined. The Company intends to initially capitalize these
costs as exploration and evaluation assets on the balance sheet. When
the technical feasibility and commercial viability of the project is
determined the costs will be transferred to property, plant and
equipment ("PP&E"). Unrecoverable costs associated with a project
will be expensed. On transition the Company will re-classify all
exploration and evaluation expenditures that are currently included
in the PP&E balance on the balance sheet.
- Development costs are expenditures for areas or projects where
technical feasibility and commercial viability have been determined.
After adopting IFRS the Company will continue to capitalize these
costs to PP&E. However, PP&E costs will be depleted on a unit of
production basis using proved or proved plus probable reserves over
an area level instead of by one company wide cost center. The Company
has not determined the areas or reserve base to be used in the
depletion calculation.
- Under IFRS, impairment of PP&E assets must be calculated at a lower
level than what is currently required under Canadian GAAP.
- ProspEx anticipates using the IFRS 1 exemption for PP&E allowing
entities to allocate their PP&E net book value balance as determined
under full cost accounting to the IFRS categories of exploration and
evaluation assets and development costs.
Draft policy and impact assessment
The Company is currently in this phase of the project which involves analyzing policy choices allowed under IFRS and assessing their impact on the financial statements. The conclusion of this phase will require the audit committee of the Board of Directors to review and approve all accounting policy choices.
Implementation and parallel reporting
This step will involve implementing all changes identified in the impact assessment phase including changes to information systems, business processes, and training of all staff impacted by the conversion.
Ongoing monitoring and IFRS policy updates
The final phase of the project involves continuing education and training and ensuring maintenance of internal controls over IFRS financial reporting and disclosure control procedures.
DISCLOSURE CONTROLS AND POLICIES
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of March 31, 2010, that the Company's disclosure controls and procedures as at such date are effective to provide reasonable assurance that material information related to the Company, including its consolidated subsidiary, is made known to them by others within those entities. It should be noted that while the Company's Chief Executive Officer and Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Chief Executive Officer and Chief Financial Officer of the Company have caused under their supervision the design of internal controls over financial reporting ("ICFR"), and have evaluated the design and effectiveness of those controls. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer of the Company have concluded that the design and operating effectiveness of the Company's ICFR as of March 31, 2010 are effective and provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.
ICFR has inherent limitations no matter how well designed such controls may be. Control systems can only provide reasonable, not absolute, assurance that the objectives of the control systems are met.
There were no significant changes to the Company's ICFR during the first quarter of 2010.
ADVISORIES
Non-GAAP Measures
Within the MD&A references are made to terms commonly used in the oil and gas industry. The following terms are not defined by GAAP in Canada and are referred to as non-GAAP measures.
The following table provides reconciliation between cash flow from operations and cash flow for the periods below:
As at As at
March 31, March 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Cash flow from operating activities 4,113 8,978
Change in non-cash working capital 1,139 (3,258)
----- -------
Cash flow 5,252 5,720
-------------------------------------------------------------------------
The following table provides a reconciliation of total net debt for the
periods below:
As at As at
March 31, March 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Accounts receivable (8,593) (8,053)
Prepaid expenses (269) (944)
Accounts payable and accrued liabilities 11,743 20,793
Long-term debt 21,356 37,471
-------------------------------------------------------------------------
Total net debt 24,237 49,267
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of gas to one barrel of oil. The term "boe" may be misleading if used in isolation. A boe conversion ratio of one barrel of oil to six mcf of gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.
"Operating netbacks" are calculated by subtracting transportation costs, royalties and operating costs from the average price received during the period.
"Total net debt" is calculated by adding long-term debt less working capital (or plus working capital deficiency), excluding fair value of commodity contracts and associated future tax assets (liabilities) and current loss on sublease.
Forward-looking Information
Certain information regarding ProspEx including, without limitation, management's assessment of future plans and operations, constitutes forward-looking information or statements under applicable securities law and necessarily involve assumptions regarding factors and risks that could cause actual results to vary materially, including, without limitation, assumptions and risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, royalty rates, imprecision of reserve estimates, environmental risks, competition, incorrect assessment of the value of acquisitions or dispositions, failure to realize the anticipated benefits of acquisitions and ability to access sufficient capital from internal and external sources.
The reader is cautioned that these factors and risks are difficult to predict and that the assumptions used in the preparation of such information, although considered reasonable by ProspEx at the time of preparation, may prove to be incorrect. Accordingly, readers are cautioned that the actual results achieved will vary from the information provided herein and the variations may be material. Readers are also cautioned that the foregoing list of assumptions, factors and risks is not exhaustive. Additional information on the foregoing assumptions, risks and other factors that could affect ProspEx's operations or financial results are included in ProspEx's public disclosure documents on file with Canadian securities regulatory authorities. In particular see "Description of the Business - Risk Factors and Industry Conditions" in ProspEx's most recent Annual Information Form. ProspEx's reports may be accessed through the SEDAR website (www.sedar.com), at ProspEx's website (www.psx.ca) or by contacting the Company directly. Consequently, there is no representation by ProspEx that actual results achieved will be the same in whole or in part as those set out in the forward-looking information.
Furthermore, the forward-looking information and statements contained in this MD&A are made as of the date of this MD&A, and ProspEx does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. The forward-looking information and statements contained herein are expressly qualified by this cautionary statement.
ProspEx Resources Ltd.
Consolidated Balance Sheets
(unaudited)
March 31, December 31,
(Stated in thousands of dollars) 2010 2009
-------------------------------------------------------------------------
Assets
Current assets (note 4)
Accounts receivable $ 8,593 7,800
Prepaid expenses 269 389
Future income tax asset (note 2) - 27
Fair value of commodity contracts (note 4) 2,103 -
------------------------
10,965 8,216
Property, plant and equipment, net 149,042 145,939
------------------------
Total assets $ 160,007 154,155
------------------------
------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 11,743 12,599
Current loss on sublease 229 226
Fair value of commodity contracts (note 4) - 93
Future income tax liability (note 2) 525 -
------------------------
12,497 12,918
Long-term debt (note 1) 21,356 17,234
Asset retirement obligation (note 5) 3,590 3,810
Other long-term liabilities 146 198
Future income tax liability (note 2) 5,427 5,160
------------------------
Total liabilities 43,016 39,320
------------------------
Shareholders' Equity
Common shares (note 3) 90,800 90,800
Contributed surplus (note 3) 9,235 8,987
Retained earnings 16,956 15,048
------------------------
Total shareholders' equity 116,991 114,835
------------------------
$ 160,007 154,155
------------------------
------------------------
Subsequent events (note 7)
See accompanying notes to consolidated financial statements
ProspEx Resources Ltd.
Consolidated Statements of Earnings (Loss), Comprehensive Earnings (Loss)
and Retained Earnings
For the three months ended March 31, (unaudited)
(Stated in thousands of dollars,
except per share amounts) 2010 2009
-------------------------------------------------------------------------
Revenue
Oil and gas (note 4) $ 10,526 12,765
Unrealized financial instrument gain (loss)
(note 4) 2,196 (828)
Royalties (1,577) (2,526)
------------------------
11,145 9,411
------------------------
Expenses
Depletion, depreciation and accretion 4,836 8,741
Operating 2,146 2,453
Transportation 417 358
General and administrative 740 905
Interest and bank charges 196 316
Stock-based compensation 124 103
------------------------
8,459 12,876
------------------------
Earnings (loss) before income taxes 2,686 (3,465)
Income taxes (note 2)
Future expense (reduction) 778 (1,240)
------------------------
Net earnings (loss) and comprehensive
earnings (loss) for the period 1,908 (2,225)
Retained earnings, beginning of period 15,048 25,485
------------------------
Retained earnings, end of period $ 16,956 23,260
------------------------
------------------------
Net earnings (loss) per share (note 3)
Basic $ 0.03 (0.04)
Diluted $ 0.03 (0.04)
------------------------
------------------------
Additional cash flow disclosure (note 5)
See accompanying notes to consolidated financial statements
ProspEx Resources Ltd.
Consolidated Statements of Cash Flows
For the three months ended March 31,
(unaudited)
(Stated in thousands of dollars) 2010 2009
-------------------------------------------------------------------------
Operations
Net earnings (loss) for the period $ 1,908 (2,225)
Items not involving cash
Depletion, depreciation and accretion 4,836 8,741
Stock-based compensation 124 103
Future income tax expense (reduction) 778 (1,240)
Unrealized financial instrument (gain) loss (2,196) 828
Amortization of rent inducements (27) -
Amortization of sublease loss (55) -
Asset retirement expenditures (116) (487)
------------------------
5,252 5,720
Changes in non-cash working capital (1,139) 3,258
------------------------
4,113 8,978
------------------------
Financing
Increase (decrease) in long-term debt 4,122 (3,336)
------------------------
4,122 (3,336)
------------------------
Investing
Exploration and development expenditures (7,858) (5,641)
Proceeds on property disposal (12) 2,078
Other capital expenditures - (3)
------------------------
(7,870) (3,566)
Changes in non-cash working capital (365) (2,076)
------------------------
(8,235) (5,642)
------------------------
Change in cash - -
Cash, beginning of period - -
------------------------
Cash, end of period $ - -
------------------------
------------------------
See accompanying notes to consolidated financial statements
Notes to Consolidated Financial Statements
For the three months ended March 31, 2010
(unaudited)
The interim unaudited consolidated financial statements of ProspEx
Resources Ltd. (the "Company" and/or "ProspEx") have been prepared in
accordance with Canadian generally accepted accounting principles
("GAAP"). The Company is engaged in the acquisition, exploration,
development and production of oil and natural gas in Canada.
The interim unaudited consolidated financial statements have been
prepared by management following the same accounting policies and methods
of computation as the audited consolidated financial statements for the
period ended December 31, 2009. Preparation of financial statements in
conformity with Canadian GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities,
revenue and expenses and disclosure of contingent assets and liabilities
at the date of the financial statements. Actual results may differ from
these estimates. In the opinion of management, these interim consolidated
financial statements contain all adjustments of a normal and recurring
nature to present fairly the Company's financial position as at March 31,
2010 and the results of its operations and cash flows for the three
months ended March 31, 2010. The disclosures included below are
incremental to those included with the annual consolidated financial
statements. The interim consolidated financial statements should be read
in conjunction with the consolidated financial statements and the notes
thereto in the Company's annual report for the year ended December 31,
2009.
1. LONG TERM DEBT
At March 31, 2010 the Company had a $33.0 million credit facility with a
major Canadian bank. The facility revolves for 364 day periods, at which
time the Company can request approval from the lender for an extension
for an additional 364 day period or convert the outstanding bank
indebtedness to a one year term loan. The facility was subject to an
annual review on May 31, 2010 but as stated below, subsequent to quarter
end this review was completed. The amount of the facility is subject to a
borrowing base test performed on a periodic basis by the lenders, based
primarily on reserves and using commodity prices estimated by the
lenders, as well as other factors. A decrease in the borrowing base could
result in a reduction of the credit facility which may require a
repayment to the lenders within sixty days of receiving notice of the new
borrowing base. The credit facility provides that advances may be made by
way of prime rate loans, guaranteed notes (bankers' acceptances) and
letters of credit. The credit facility is tested quarterly, in arrears,
and bears interest based on a sliding scale. The interest rate varies
depending on the Company's debt to cash flow ratio determined quarterly
on a grid system, with the grid ranging from debt to cash flow ranges of
lower than 1.0:1.0 to greater than 3.0:1.0.
The facility is secured by a general security agreement conveying a first
floating charge over all real and personal property and after-acquired
assets. The Company is required to meet certain financial based covenants
under the terms of this facility. As at March 31, 2010, the Company is in
compliance with all covenants in accordance with the terms of the credit
facility.
Subsequent to the quarter the Company completed its annual credit review
and has increased its credit facility to $40.0 million. The next
scheduled review will be on May 31, 2011.
2. FUTURE INCOME TAXES
The provision for future income taxes differs from the amount computed by
applying the combined expected Canadian Federal and Provincial tax rates
to earnings before income taxes. The reasons for these differences are as
follows:
Three Three
months months
ended ended
March 31, March 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Earnings (loss) before income taxes $ 2,686 $ (3,465)
Combined statutory rate (%) 28.0% 29.0%
-------------------------------------------------------------------------
Computed expected future income tax expense
(reduction) 752 (1,005)
Increase (decrease) in taxes resulting from:
Stock-based compensation expensed 35 30
Effect of change in tax rate (9) (279)
Other - 14
-------------------------------------------------------------------------
Income tax expense (reduction) $ 778 $ (1,240)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The components of the future income tax liability are as follows:
March 31, December 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Property, plant and equipment $ (5,997) $ (5,900)
Fair value of commodity contracts (589) 27
Asset retirement obligation 897 952
Loss due to leasing arrangements 126 146
Share issue costs 111 142
-------------------------------------------------------------------------
(5,452) (4,633)
Valuation allowance (500) (500)
-------------------------------------------------------------------------
Future income tax liability $ (5,952) $ (5,133)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At March 31, 2010, the Company had estimated tax pools available to
reduce future taxable income of $127.1 million (December 31, 2009 -
$124.5 million).
Capitalized stock based compensation resulted in an increase to future
tax liabilities of $0.1 million during the quarter (2009 - $0.1 million).
3. SHAREHOLDERS' EQUITY
(a) Common Shares & Common Share Performance Warrants Issued
Three months ended Three months ended
March 31, 2010 March 31, 2009
-------------------------------------------------------------------------
Number
Number of Shares/
of Shares Amount Warrants Amount
(000's) ($000's) (000's) ($000's)
-------------------------------------------------------------------------
Common shares
Balance at the beginning
and end of period 57,385 $ 90,800 57,385 $ 90,802
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Common share performance
warrants
Balance at the beginning
and end of period - $ - 2,016 $ 1,233
-------------------------------------------------------------------------
(b) Contributed Surplus
Three Three
months months
ended ended
March 31, March 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Balance at the beginning of the period $ 8,987 $ 6,758
Stock-based compensation 248 207
-------------------------------------------------------------------------
Balance at the end of the period $ 9,235 $ 6,965
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(c) Stock Options
Changes in outstanding stock options are summarized below:
Three months ended Three months ended
March 31, 2010 March 31, 2009
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Options Exercise Options Exercise
(000's) Price (000's) Price
-------------------------------------------------------------------------
Outstanding at beginning
of period 5,261 $ 2.34 5,160 $ 3.44
Forfeited - - (57) 3.36
Expired (85) 3.22 - -
-------------------------------------------------------------------------
Outstanding at end of period 5,176 $ 2.32 5,103 $ 3.45
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The following table summarizes stock options outstanding and exercisable
at March 31, 2010:
Options outstanding Options exercisable
-------------------------------------------------------------------------
Number of Weighted
outstanding average Number
at remaining Weighted exercisable Weighted
Range of period contractual average at period average
exercise end life exercise end exercise
price (000's) (years) price (000's) price
-------------------------------------------------------------------------
$0.61 - 0.92 1,110 4.3 $ 0.66 - -
$0.93 - 1.40 1,458 4.4 $ 1.01 87 $ 1.25
$2.13 - 3.20 250 2.7 $ 3.01 166 $ 3.01
$3.21 - 4.46 2,358 1.9 $ 3.84 1,997 $ 3.86
-------------------------------------------------------------------------
5,176 3.2 $ 2.32 2,250 $ 3.70
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The estimated fair values of the options are being amortized against
earnings and capitalized to property plant and equipment over the vesting
period. During the three months ended March 31, 2010, a total of
$0.1 million (2009 - $0.1 million) of stock-based compensation was
recorded against income and $0.1 million (2009 - $0.1 million) was
capitalized.
(d) Per Share Amounts
Three Three
months months
ended ended
March 31, March 31,
2010 2009
-------------------------------------------------------------------------
Weighted average common shares basic 57,385,162 57,385,162
Dilutive securities:
Stock options 722,901 -
-------------------------------------------------------------------------
Diluted 58,108,063 57,385,162
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three months ended March 31, 2010, 2,608,334 stock options (2009
- 5,102,887 stock options and 2,016,269 warrants) were excluded from the
diluted calculations as they were anti-dilutive.
4. FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT
STRATEGY
Overview
The Company has exposure to a number of risks from its use of financial
instruments including:
- Credit risk
- Liquidity risk
- Market risk
This note presents information about the Company's exposure to each of
the above risks and the Company's objectives, policies and processes for
measuring and managing risk, and the Company's management of capital.
Further quantitative disclosures are included throughout these financial
statements.
The Board of Directors has overall responsibility for the establishment
and oversight of the Company's risk management framework. The Board has
implemented and monitors compliance with risk management policies.
The Company's risk management policies are established to identify and
analyze the risks faced by the Company, to set appropriate risk limits
and controls, and to monitor risks and adherence to market conditions and
the Company's activities.
Fair Value of Financial Instruments
The Company's risk management policies are established to identify and
analyze the risks faced by the Company, to set appropriate risk limits
and controls, and to monitor risks and adherence to market conditions and
the Company's activities. The fair value of measurements recognized in
the balance sheet are classified according to the following hierarchy
based on the amount of observable inputs used to value the instrument.
- Level 1 - Quoted prices are available in active markets for
identical assets or liabilities as of the reporting date. Active
markets are those in which transactions occur in sufficient
frequency and volume to provide pricing information on an ongoing
basis.
- Level 2 - Pricing inputs are other than quoted prices in active
markets included in Level 1. Prices are either directly or
indirectly observable as of the reporting date. Level 2 valuations
are based on inputs, including quoted forward prices for
commodities, time value and volatility factors, which can be
substantially observed or corroborated in the market place.
- Level 3 - Valuations in this level are those with inputs for the
asset or liability that are not based on observable market data.
March 31, 2010
---------------------------------------------------
Fair Value Level 1 Level 2 Level 3
-------------------------------------------------------------------------
Commodity Contracts 2,103 - 2,103 -
-------------------------------------------------------------------------
The Company's use of financial instruments has been assessed on the fair
value hierarchy described above and the natural gas contracts are
classified as Level 2.
The carrying value of the Company's financial instruments, other than
bank indebtedness approximates their fair value due to their short
maturity.
Credit Risk
Credit risk relates to the Company's receivables from joint venture
partners and petroleum and natural gas marketers and the risk of
financial loss if a customer, partner or counterparty to a financial
instrument fails to meet its contractual obligations. A substantial
portion of the Company's accounts receivable are with customers in the
energy industry and are subject to normal industry credit risk. The
Company generally grants unsecured credit but routinely assesses the
financial strength of its partners and marketers.
Receivables from petroleum and natural gas marketers are normally
collected on the 25th day of the month following production. The Company
sells the majority of its production to two petroleum and natural gas
marketers therefore is subject to concentration risk. To date the Company
has not experienced any collection issues with its petroleum and natural
gas marketers. Joint venture receivables are typically collected within
one to three months of the joint venture bill being issued to the
partner. The Company attempts to mitigate the risk from joint venture
receivables by obtaining joint venturer approval of significant capital
expenditures prior to expenditure. The Company does not typically obtain
collateral from petroleum and natural gas marketers or joint venturers;
however in certain circumstances, it may elect to cash call a joint
venturer in advance of the work.
As at March 31, 2010 the Company's receivables consisted of $2.9 million
(December 31, 2009 - $2.7 million) from joint venturers, $3.9 million
(December 31, 2009 - $3.5 million) of receivables from petroleum and
natural gas marketers and $1.8 million (December 31, 2009 - $1.6 million)
of other receivables. Of the $8.6 million in total accounts receivable,
$0.4 million is aged over 90 days.
The carrying amount of accounts receivable and cash and cash equivalents
represents the maximum credit exposure. The Company does not have an
allowance for doubtful accounts as at March 31, 2010 and did not provide
for any doubtful accounts nor was it required to write-off any
receivables during the quarter ended March 31, 2010.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its
financial obligations as they are due. The Company's approach to managing
liquidity is to ensure, as far as possible, that it will have sufficient
liquidity to meet its liabilities when due, under both normal and
stressed conditions without incurring unacceptable losses or risking harm
to the Company's reputation.
The Company prepares annual capital expenditure budgets, which are
regularly monitored and updated as considered necessary. Further, the
Company utilizes authorizations for expenditures on both operated and
non-operated projects to further manage capital expenditures. To
facilitate the capital expenditure program, the Company has a revolving
reserve based credit facility, as outlined in note 1. The Company also
attempts to match its payment cycle with collection of petroleum and
natural gas revenues on the 25th day of each month.
The following are the contractual maturities of financial liabilities and
associated interest payments due as at March 31, 2010:
-------------------------------------------------------------------------
Financial
Liability (less than)
($000's) 1 year 1 - 2 years 2 - 5 years Thereafter
-------------------------------------------------------------------------
Accounts payable and
accrued liabilities $ 11,743 - - -
Long-term debt - 21,356 - -
-------------------------------------------------------------------------
Total $ 11,743 21,356 - -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Market risk
Market risk is the risk that changes in market prices, such as foreign
exchange rates, commodity prices, and interest rates will affect the
Company's net earnings or the value of financial instruments. The
objective of market risk management is to manage and control market risk
exposures within acceptable limits, while maximizing returns.
The Company utilizes both financial derivatives and physical delivery
sales contracts to manage market risks. All such transactions are
conducted in accordance with the risk management policy that has been
approved by the Board of Directors.
Foreign Currency Exchange Risk
Foreign currency exchange rate risk is the risk that the fair value of
financial instruments or future cash flows will fluctuate as a result of
changes in foreign exchange rates. Although substantially all of the
Company's petroleum and natural gas sales are denominated in Canadian
dollars, the underlying market prices in Canada for petroleum and natural
gas are impacted by changes in the exchange rate between the Canadian and
United States dollars. Given that changes in exchange rate have an
indirect influence, the impact of changing exchange rates can not be
accurately quantified. The Company had no forward exchange rate contracts
in place as at or during the three months ended March 31, 2010.
Commodity Price Risk
Commodity price risk is the risk that the fair value of financial
instruments or future cash flows will fluctuate as a result of changes in
commodity prices. Commodity prices for petroleum and natural gas are
impacted by world economic events that dictate the levels of supply and
demand. The Company attempts to mitigate commodity price risk through the
use of financial derivative sales contracts. The following contracts were
in place as of March 31, 2010.
Type Amount (GJ/day) Term Price ($/GJ at AECO) Type
---- --------------- ---- -------------------- ----
Fixed 1,000 Apr. 1 - Oct. 31, 2010 $5.18 Financial
Fixed 1,000 Apr. 1 - Oct. 31, 2010 $5.385 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $5.00 - $6.16 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $5.00 - $5.90 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $4.90 - $5.63 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $5.00 - $5.95 Financial
Collar 1,000 Apr. 1 - Oct. 31, 2010 $4.75 - $5.86 Financial
The contracts in place during the three months ended March 31, 2010
resulted in an unrealized gain of $2.2 million (March 31, 2009 -
$0.8 million loss) and a realized loss of $0.1 million (March 31, 2009 -
$1.3 million gain), which is included in oil and gas revenue.
With respect to commodity prices, during the three months ended March 31,
2010, a one dollar increase in the price per GJ of natural gas relevant
only to the Company's production dedicated to derivative financial
instruments would have resulted in a net earnings increase of
$0.3 million (2009 - decrease of $0.1 million). A one dollar decrease in
the price per GJ of natural gas on the same production would have
decreased net earnings after taxes for the three months ended March 31,
2010 by $0.1 million (2009 - increase of $0.1 million). This excludes any
impact relating to unrealized financial instrument gains/losses.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a
result of changes in market interest rates. The Company is exposed to
interest rate fluctuations on its credit facility which bears a floating
rate of interest. The Company had no interest rate swaps or financial
contracts in place as at or during the three months ended March 31, 2010.
For the three months ended March 31, 2010, a difference in the interest
rate of 1% would change net earnings after tax by an estimated
$0.03 million (2009 - $0.1 million), assuming all other variables are
constant.
Capital Management Strategy
The Company's policy on capital management is to maintain a prudent
capital structure to allow the Company to fund future development. The
Company considers its capital structure to include shareholders' equity,
bank debt, and working capital.
March 31, December 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Shareholders' equity $ 116,991 $ 114,835
Long-term debt 21,356 17,234
Working capital deficiency excluding unrealized
financial instrument gain or losses,
associated future tax assets or liabilities
and current loss on sublease 2,881 4,410
-------------------------------------------------------------------------
The Company manages its capital programs in order to maintain a prudent
capital structure as changes in economic conditions occur. The Company
may and has from time to time issued shares and adjusted spending to
manage current or projected operating cash flows and debt levels.
The Company monitors its capital base using the ratio of net debt to
annualized operating cash flow. This ratio is calculated as total net
debt, as defined as long term debt less working capital (or plus working
capital deficiency) excluding unrealized financial instrument gain (loss)
and associated future tax assets (liabilities); divided by annualized
cash flow from operations before changes in non-cash working capital
(based on the most recent operating quarter). The Company's guideline is
to maintain a ratio of approximately 1.0 to 1.0, not exceeding 2.0 to
1.0. This ratio will fluctuate depending on fluctuations of the commodity
and business cycles. The Company prepares annual capital expenditure
budgets which are updated periodically to monitor this ratio. The annual
budget is approved by the Board of Directors with updates reviewed by the
Board throughout the year.
As at March 31, 2010 the Company's ratio of net debt to annualized cash
flow was 1.2 to 1.0, and compares to the ratio of 1.7 to 1.0 for the year
ended December 31, 2009.
The Company's share capital is not subject to any external restrictions.
As at March 31, 2010, the Company is in compliance with all flow-through
share expenditure requirements as well as all bank facility requirements.
There have been no changes to the Company's capital management strategy
during the quarter ended March 31, 2010.
5. ADDITIONAL DISCLOSURES
(a) Interest and Taxes Paid
Net cash interest paid during the quarter was $0.2 million (2009 -
$0.5 million). Cash taxes paid during the period was $nil (2009 - $nil).
(b) Asset Retirement Obligation
For the quarter ended March 31, 2010, asset retirement obligation
decreased by $0.2 million (March 31, 2009 - $1.1 million increase), with
a corresponding decrease to property, plant and equipment.
6. COMMITMENTS
The Company has committed to certain future payments as follows:
Payments due There-
($000's) 2010 2011 2012 2013 2014 after Total
-------------------------------------------------------------------------
Long-term
debt $ - $21,356 $ - $ - $ - $ - $21,356
Building
lease 702 1,051 1,356 1,433 358 - 4,900
Processing
fees 284 63 - - - - 347
Transpor-
tation 334 443 147 - - - 924
Other 3 - - - - - 3
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total $ 1,323 $22,913 $ 1,503 $ 1,433 $ 358 $ - $27,530
-------------------------------------------------------------------------
7. SUBSEQUENT EVENTS
Subsequent to the quarter end, the Company amended its agreement to
process and gather raw gas at the Musreau Gas Plant. This amendment
extends the Company's firm commitment for capacity at the plant to
February 28, 2015. The total obligation is estimated to be $2.7 million
over the life of this agreement.
The Company completed the annual renewal of their credit facility with a
major Canadian bank in April 2010. The facility was increased at this
time to a total of $40.0 million and is not scheduled to be reviewed
again until May 31, 2011.
%SEDAR: 00021285E
For further information: John Rossall, President & CEO or George Yee, Vice President Finance & Chief Financial Officer, at [email protected] or (403) 268-3940
Share this article