ProspEx Announces 2010 Second Quarter Results
(All amounts are in Canadian dollars, unless stated otherwise)
CALGARY, July 28 /CNW/ - ProspEx Resources Ltd. ("ProspEx" or the "Company") announces its financial and operating results for the three and six months ended June 30, 2010.
HIGHLIGHTS
- Production for the second quarter increased to 3,086 barrels of oil
equivalent ("boe") per day, compared to 2,994 boe per day in the
first quarter of 2010.
- The traditional spring break up period and wet weather in the second
quarter curtailed the Company's capital program. Total capital
expenditures were $3.1 million during the second quarter of 2010,
slightly less than cash flow for that period.
- ProspEx resumed horizontal drilling activity in the Falher play at
Kakwa in early July, with a three well program planned for the
summer. Drilling at Pembina in West Central Alberta is expected to
commence as soon as surface access conditions permit.
- Second quarter cash flow (before changes in non-cash working capital
items) was $3.5 million, compared to $2.5 million in the prior year's
quarter reflecting increases in overall commodity prices.
OPERATIONAL REVIEW
Capital Program
Total capital expenditures were $3.1 million during the second quarter of 2010. As the spring break up period restricted drilling activity, the majority of these expenditures were attributable to acquisitions at Crown land sales, new seismic data and expansion of compression facilities in Kakwa.
ProspEx's drilling activity continues to focus on horizontal drilling of liquids rich, Cretaceous age, natural gas targets. The Company's summer drilling program was delayed due to wet weather in the second quarter impairing access to drilling locations. At Kakwa in the Deep Basin, the Company has now commenced its summer drilling program, and is currently drilling the first horizontal well of a planned three (1.5 net) well program targeting the Falher formation, following up on a successful drilling program over the past winter.
At Pembina in West Central Alberta, ProspEx plans to spud its first horizontal well (100% working interest) in August, contingent on surface access conditions. This well is to also target the Falher formation, and be ProspEx's first well on a land position acquired in 2009.
ProspEx continues to plan a capital budget of $30.0 million (net of Alberta Royalty Drilling Credits) for 2010, contingent on commodity prices. Capital spending for the period July 1 to December 31, 2010 is therefore expected to be approximately $19.0 million. The drilling program planned for this period includes approximately six horizontal wells, including the summer drilling described above.
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 of the Company for 2010.
Production
Production (boe/d) Q2 2010 Q1 2010 Q4 2009 Q3 2009 Q2 2009
-------------------------------------------------------------------------
West Central Alberta 925 1,030 1,280 1,289 1,635
Deep Basin 2,129 1,953 1,183 675 944
Southern Alberta 25 3 6 7 503
Other Areas 7 8 8 7 7
-------------------------------------------------------------------------
Total 3,086 2,994 2,477 1,978 3,089
Second quarter 2010 production averaged 3,086 boe per day, increasing from first quarter 2010 production of 2,994 boe per day, as the benefits of a full quarter of production from wells brought on stream in the first quarter were partially offset by natural production declines.
No new production was brought on stream during the second quarter due to spring break up and wet weather in June, however the Company has received all required approvals to tie in the horizontal well drilled in Brazeau during the first quarter, and will start this project as soon as surface access conditions permit.
ProspEx's three horizontal wells in Kakwa have been on production for 4 to 8 months, and continue to produce at high rates, with estimated gross raw gas production in June ranging from 2.7 to 5.5 mmcf per day per well, plus natural gas liquids. Further information on the production of these wells is available on the Company's website at www.psx.ca.
Given the weather related delay in starting the summer drilling program, ProspEx is adjusting its forecast of annual average production for 2010 to a range of 3,100 to 3,300 boe per day, compared to the previous guidance of 3,300 to 3,500 boe per day.
Including expected additions from the summer drilling program, production in late 2010 is anticipated to be 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 approximately 50% production growth over the year.
ProspEx continues to monitor natural gas prices and may elect to curtail production in the event of deterioration in summer prices. The guidance given above assumes that there are no voluntary production curtailments due to low gas prices.
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
Second quarter cash flow (before changes in non-cash working capital items) was $3.5 million, compared to $5.3 million in the first quarter, as declines in commodity prices more than offset increased production. Total capital spending, net of dispositions and other capital assets, of $3.1 million was slightly less than cash flow.
Total net debt (excluding the fair value of commodity contracts, the current loss on office sublease and associated future taxes) at June 30, 2010 was $23.8 million which is equivalent to 1.8 years net debt to annualized trailing cash flow. During the second quarter, 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 July 1, 2010 to September 1, 2010 for 7,000 Gigajoules ("GJ") per day of gas production, with an average minimum price of approximately $5.03/GJ for the hedged volumes. For the period September 1, 2010 to October 31, 2010 the Company has hedges in place for 9,000 GJ per day of gas production, with an average minimum price of approximately $4.80/GJ for the hedged volumes. Details of the individual hedges are provided in the Company's second quarter Management Discussion and Analysis. As forward prices for natural gas over the summer of 2010 remain weak, these hedges are expected to 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, current loss on sublease and associated future tax assets (liabilities).
ProspEx Resources Ltd.
Consolidated Highlights
For the periods ended
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
(unaudited) 2010 2009 2010 2009
-------------------------------------------------------------------------
FINANCIAL ($000's)
Oil and gas revenue 9,564 7,370 20,090 20,135
Net (loss) earnings (1,900) (3,899) 8 (6,124)
Cash flow(1) 3,487 2,475 8,739 8,196
Total assets 154,936 159,790 154,936 159,790
Total net debt(2) 23,772 23,032 23,772 23,032
Net (loss) earnings per
share ($ per share)
Basic (0.03) (0.07) 0.00 (0.11)
Diluted (0.03) (0.07) 0.00 (0.11)
Cash flow per share
($ per share)(1)
Basic 0.06 0.04 0.15 0.14
Diluted 0.06 0.04 0.15 0.14
Weighted average
common shares (000's)
Basic 57,385 57,385 57,385 57,385
Diluted 57,385 57,385 57,995 57,385
PRODUCTION VOLUMES
Natural gas (mcf/d) 14,996 14,382 14,644 15,963
Natural gas liquids
(bbls/d) 562 645 572 728
Oil (bbls/d) 26 47 27 58
------------------------------------------------
Total (boe/d) 3,086 3,089 3,040 3,446
SALES PRICES
Natural gas ($/mcf) 4.70 3.89 5.20 5.15
Natural gas liquids
($/bbl) 57.98 34.15 57.03 35.21
Oil ($/bbl) 82.75 64.40 83.00 57.82
------------------------------------------------
Total ($/boe) 34.05 26.22 36.51 32.28
OPERATING NETBACKS
($/boe)
Price 34.05 26.22 36.51 32.28
Royalties (7.49) (1.21) (6.69) (4.60)
Operating costs (7.90) (9.30) (7.93) (8.12)
Transportation (1.50) (0.93) (1.52) (0.99)
------------------------------------------------
Total 17.16 14.78 20.37 18.57
CAPITAL ($000's)
Drilling and completions 172 104 5,391 3,690
Facilities 882 (914) 2,154 (27)
Land and lease 1,028 1,568 1,722 1,889
Seismic 516 98 559 148
Capitalized general
and administrative 640 763 1,270 1,561
------------------------------------------------
Total exploration
& development 3,238 1,619 11,096 7,261
Net property
dispositions (208) (25,383) (196) (27,461)
Other capital assets 21 4 21 7
------------------------------------------------
Total 3,051 (23,760) 10,921 (20,193)
(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, current loss on sublease and associated future taxes.
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 and six months ended June 30, 2010, and was prepared as at July 28, 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 and six months ended June 30, 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 second quarter saw reduced operational activity, with a wetter than normal spring break up period limiting access to the Company's operating areas. ProspEx did not participate in the drilling of any wells during the quarter, but did spend $1.5 million on the acquisition of Crown land and seismic data along with $0.9 million in facilities construction in Kakwa. Total capital expenditures net of dispositions and other capital assets in the quarter were $3.1 million.
Overall production levels were flat compared to the second quarter of the prior year, as the production loss from the properties disposed of in 2009 was offset by the production added in Kakwa. Cash flow for the quarter rose to $3.5 million, 41% higher than the prior year's quarter of $2.5 million, due to a 16% increase in operating netbacks.
During the quarter the Company completed its annual credit review and increased its credit facility to $40.0 million. Total net debt as at June 30, 2010 (excluding the fair value of commodity contracts, current loss on office sublease and associated future taxes) was $23.8 million, which is equivalent to a 1.8 to 1.0 ratio of trailing cash flow annualized. The next scheduled review date of the facility is May 31, 2011.
Business Environment
Overall business conditions continue to improve but confidence remains fragile as concerns of a double dip recession remain, leading to uncertainty in capital markets. Natural gas markets continue to reflect concern over supply and demand fundamentals of the North American natural gas markets resulting in the deterioration of natural gas prices over the second quarter.
ProspEx's 2010 capital spending objectives continue to target the capture and evaluation of new opportunities. This activity is oriented towards increasing the opportunity set available to the Company as business conditions improve, rather than short term production growth.
Revenue
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($000's) 2010 2009 2010 2009
-----------------------------------------------
Natural gas $ 5,533 $ 5,092 $ 12,990 $ 13,578
Realized gain on
financial instruments 875 - 780 1,316
-----------------------------------------------
Total natural gas 6,408 5,092 13,770 14,894
Oil 193 272 411 602
Natural gas liquids 2,963 2,006 5,909 4,639
-----------------------------------------------
Oil and gas revenue 9,564 7,370 20,090 20,135
Unrealized (loss) gain on
financial instruments (1,058) 310 1,138 (517)
-----------------------------------------------
Total revenue $ 8,506 $ 7,680 $ 21,228 $ 19,618
-----------------------------------------------
Second quarter oil and gas revenue of $9.6 million in 2010 increased by $2.2 million or 30%, compared to $7.4 million in the second quarter of 2009. The increase in revenues for the quarter was due to the combination of slightly higher production levels, stronger natural gas liquids pricing and realized gains from the 2010 hedging program.
Production
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
-----------------------------------------------
Area (boe/d)
------------
Deep Basin 2,129 944 2,041 965
West Central Alberta 925 1,635 977 1,866
Southern Alberta 25 503 14 607
Other Areas 7 7 8 8
-----------------------------------------------
3,086 3,089 3,040 3,446
Product
-------
Natural gas (mcf/d) 14,996 14,382 14,644 15,963
Natural gas liquids
(bbls/d) 562 645 572 728
Oil (bbls/d) 26 47 27 58
-----------------------------------------------
Total (boe/d) 3,086 3,089 3,040 3,446
Overall production remained flat compared to the prior year as increases in production seen in the Deep Basin as a result of the successful horizontal drilling program in Kakwa were offset by the sale of production from non-core assets at Medallion and West Central Alberta in 2009.
Second quarter production increased 3% relative to the first quarter of 2010, reflecting a full quarter's production from new wells in Kakwa, offset by natural declines. No new wells were brought on production in the quarter.
ProspEx's summer drilling program has been delayed due to wet weather in the second quarter which impaired surface access to drilling locations. With the delays in the summer drilling program, the Company now forecasts its annual average production for 2010 to be 3,100 to 3,300 barrels of oil equivalent ("boe") per day, compared to the previous guidance of 3,300 to 3,500 boe per day.
Production in late 2010 is expected to be approximately 4,000 boe per day, as a result of the summer drilling program that has recently commenced with the return to drilling in the Kakwa area. Production at the start of 2010 was approximately 2,700 boe per day, the forecasted 4,000 boe per day exit rate equates to approximately 50% production growth over the year.
Guidance regarding production may constitute a "financial outlook" as contemplated by National Instrument 51-102 of the Canadian Securities Administrators entitled Disclosure Obligations ("NI 51-102"). The purpose of such guidance is to forecast the anticipated production for the Company for 2010.
Commodity Pricing
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
ProspEx Average Prices 2010 2009 2010 2009
-----------------------------------------------
Natural gas ($/mcf)
Sales price $ 4.06 $ 3.89 $ 4.91 $ 4.69
Realized gain on
financial instruments 0.64 - 0.29 0.46
-----------------------------------------------
4.70 3.89 5.20 5.15
Oil ($/bbl) 82.75 64.40 83.00 57.82
NGL ($/bbl) 57.98 34.15 57.03 35.21
-----------------------------------------------
Average realized price
($/boe) 34.05 26.22 36.51 32.28
Unrealized (loss) gain
on financial
instruments ($/boe) (3.77) 1.10 2.07 (0.83)
-----------------------------------------------
Total average price
($/boe) $ 30.28 $ 27.32 $ 38.58 $ 31.45
-----------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
Benchmark pricing 2010 2009 2010 2009
-----------------------------------------------
AECO C Spot ($/mcf) $ 3.89 $ 3.62 $ 4.42 $ 4.27
Edmonton Par - light
oil ($/bbl) $ 75.14 $ 62.90 $ 77.63 $ 56.28
-----------------------------------------------
Average natural gas sales prices (prior to the effects of realized financial instruments) increased 4% to $4.06 per thousand cubic feet ("mcf") in the second quarter of 2010, compared to $3.89 per mcf in the second quarter of 2009. This price reflects a slight improvement in natural gas markets, but remains significantly lower than historical averages and is 30% lower than prices received in the first quarter of 2010. Overall market sentiment still reflects concerns over the potential of an over supply of North American natural gas market in the near term.
Benchmark AECO C daily spot prices for natural gas increased 7% compared to the second quarter of 2009, compared to the increase of 4% in the Company's natural gas sales price, as production from the Company's most recent Kakwa well is sold through the Alliance pipeline system and received lower pricing in the second quarter.
Realized gains in the natural gas hedging program for 2010 increased the realized price for natural gas sales by $0.64 per mcf for the quarter and $0.29 per mcf on a year to date basis. The results of the hedging program reflect the Company's efforts to create a more predictable operating cash flow and thus ensure an orderly 2010 capital program.
Oil prices received for the second quarter of 2010 were $82.75 per barrel ("bbl"). This is a 28% increase from the $64.40 per bbl received in the second quarter of 2009, consistent with the increase in benchmark pricing. The price realized for natural gas liquids ("NGLs") in the second quarter of 2010 was $57.98 per bbl, an increase of 70% from $34.15 per bbl in the second quarter of 2009. Overall, oil and NGL prices have recovered substantially, as the world economy recovered over the past year.
Financial Instruments
The impact of the changes in the fair values of open financial instruments during the quarter ended June 30, 2010 was an unrealized loss of $1.1 million and a year to date unrealized gain of $1.1 million. This compares to an unrealized gain of $0.3 million for the second quarter of 2009 and an unrealized loss of $0.5 million on a year to date basis.
On a realized basis, gains from financial instruments were $0.9 million in the current quarter of 2010 and $0.8 million year to date.
The financial instruments open as of June 30, 2010 are described below:
Amount
Type (GJ/day) Term Price ($/GJ at AECO) Type
---- -------- ---- -------------------- ----
Fixed 1,000 Jul. 1 - Oct. 31, 2010 $5.18 Financial
Fixed 1,000 Jul. 1 - Oct. 31, 2010 $5.385 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $5.00 - $6.16 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $5.00 - $5.90 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $4.90 - $5.63 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $5.00 - $5.95 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $4.75 - $5.86 Financial
Fixed 1,000 Sept. 1 - Oct. 31, 2010 $4.05 Financial
Fixed 1,000 Sept. 1 - Oct. 31, 2010 $3.96 Financial
These open financial instruments represent a mark to market asset at June 30, 2010 of $1.0 million, as current natural gas forward prices are below the minimum prices that these open financial instruments receive.
Royalty Expenses
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($000's) 2010 2009 2010 2009
-----------------------------------------------
Crown $ 1,707 $ (42) $ 2,974 $ 1,973
Freehold and gross
overriding 396 383 706 894
-----------------------------------------------
Total Royalties $ 2,103 $ 341 $ 3,680 2,867
-----------------------------------------------
$ per boe $ 7.49 $ 1.21 $ 6.69 $ 4.60
As a percentage of oil
and gas revenue 22% 5% 18% 14%
-----------------------------------------------
In the second quarter of 2010, royalties totaled $2.1 million or 22% of revenue compared to the previous year's $0.3 million or 5% of revenue. During the first six months of 2010 royalties totaled $3.7 million or 18% of oil & gas revenue compared to $2.9 million or 14% of oil & gas revenue for the same period of 2009.
Crown royalty payments increased in the quarter compared to the first quarter of 2010 and to the prior year. This was due to production from new wells at Kakwa reaching the volume limit for the reduced 5% initial Crown royalty rate and a $0.5 million reduction in the annual capital cost allowance for 2009.
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 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 the New Well Incentive Program is to become a permanent feature to the new oil and gas royalty framework. Further refinements to the amendments were announced by the Government of Alberta on May 27, 2010 including finalization of the royalty curves that are to be utilized to determine the applicable royalty rates, and the indefinite extension and adjustments to the New Gas Deep Drilling Program.
Operating Costs
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
-----------------------------------------------
Operating costs ($000's) $ 2,218 $ 2,613 $ 4,364 $ 5,066
Operating costs ($/boe) $ 7.90 $ 9.30 $ 7.93 $ 8.12
Operating costs for the second quarter were $2.2 million or $7.90 per boe, compared to $2.6 million or $9.30 per boe in the second quarter of 2009.
Operating costs on a unit basis have decreased compared to 2009, reflecting the disposition of higher operating cost areas, and the addition of production from horizontal wells in Kakwa.
Transportation Expense
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
-----------------------------------------------
Transportation expenses
($000's) $ 420 $ 262 $ 837 $ 619
Transportation expenses
($/boe) $ 1.50 $ 0.93 $ 1.52 $ 0.99
Transportation expense per boe for the three and six months ended June 30, 2010 increased compared to the prior year, reflecting increases in production in operating areas that attract higher transportation rates and the disposition of production in areas with lower transportation costs.
General and Administrative Expenses
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($000's) 2010 2009 2010 2009
-----------------------------------------------
Gross general and
administrative $ 1,642 $ 1,769 $ 3,243 $ 3,718
Recoveries (318) (155) (549) (400)
Capitalized expenses (640) (763) (1,270) (1,561)
----------- ----------- ----------- -----------
Net general and
administrative expenses $ 684 $ 851 $ 1,424 $ 1,757
Net general and
administrative
expenses ($/boe) $ 2.43 $ 3.03 $ 2.59 $ 2.82
Gross general and administrative costs for the second quarter of 2010 remained approximately the same compared to the first quarter of 2010 and were slightly lower than the same periods in 2009 due to lower staff levels in 2010.
Interest and Bank Charges
Interest and bank charges of $0.4 million in the second quarter and $0.5 million year to date in 2010 were slightly lower compared to the prior year amount of $0.4 million in the second quarter and $0.8 million year to date. This is due to the Company operating at lower debt levels compared to the prior year.
Depletion, Depreciation and Accretion
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
-----------------------------------------------
Depletion, depreciation
and accretion ($000's) $ 5,141 $ 8,247 $ 9,977 $ 16,988
Depletion, depreciation
and accretion ($/boe) $ 18.30 $ 29.34 $ 18.13 $ 27.24
Depletion, depreciation and accretion expense per boe in the second quarter of 2010 was $18.30 per boe. This is a 38% decrease from the second quarter 2009 rate of $29.34 per boe. This decrease reflects the impact of reserve additions at year end and the first quarter of 2010 within the Kakwa operating area.
Income Taxes
In the second quarter of 2010, the Company had a future income tax reduction of $0.6 million compared to a reduction of $1.8 million in the same period in 2009. For the six months ending June 30, 2010 future income tax expense totaled $0.2 million, compared to a $3.0 million reduction in June of 2009.
Estimated tax pools as at June 30:
($000's) 2010 2009
-------------------------------------------------------------------------
Canadian development expense $ 25,683 $ 37,473
Canadian exploration expense 35,611 32,101
Canadian oil & gas property expense 20,757 18,649
Undepreciated capital cost 26,576 33,283
Non Capital Losses 14,847 -
Other 3,092 4,499
-------------------------------------------------------------------------
$ 126,566 $ 126,005
-------------------------------------------------------------------------
Net Earnings
The Company reported a net loss of $1.9 million for the second quarter of 2010 ($3.9 million loss in 2009) resulting in negligible net earnings year to date compared to prior year to date losses of $6.1 million. Net losses in the quarter and year to date were lower than the prior year due to a lower depletion, depreciation and accretion rate.
Capital Expenditures
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($000's) 2010 2009 2010 2009
-------------------------------------------------------------------------
Drilling and completions $ 172 $ 104 $ 5,391 $ 3,690
Facilities 882 (914) 2,154 (27)
Land and lease 1,028 1,568 1,722 1,889
Seismic 516 98 559 148
Capitalized G&A 640 763 1,270 1,561
-----------------------------------------------
Exploration & development
capital expenditures 3,238 1,619 11,096 7,261
Net property dispositions (208) (25,383) (196) (27,461)
Other capital expenditures 21 4 21 7
-------------------------------------------------------------------------
Total net capital
expenditures $ 3,051 $ (23,760) $ 10,921 $ (20,193)
-------------------------------------------------------------------------
For the second quarter of 2010, the Company did not participate in any drilling as spring break up restricted access to drilling locations. Of the $3.2 million invested in exploration and development capital expenditures, $1.5 million was spent on the acquisition of new undeveloped lands and seismic, and $0.9 million spent on facilities work in the Kakwa area.
The Company's 2010 summer drilling program was delayed due to wet weather in the second quarter which impaired surface access to drilling locations. At Kakwa in the Deep Basin, the Company has now commenced its summer drilling program, and is currently drilling the first horizontal well of a planned three (1.5 net) well program targeting the Falher formation. At Pembina in West Central Alberta, ProspEx plans to spud its first horizontal well (100% working interest) in early August, contingent on surface access conditions, which is to also target the Falher formation.
ProspEx maintains a capital budget of $30.0 million (net of Alberta Royalty Drilling Credits) for 2010, contingent on commodity prices. Capital spending for the period July 1 to December 31, 2010 is therefore expected to be approximately $19.0 million. The capital program planned for this period includes approximately six horizontal wells, including fourth quarter drilling in West Central Alberta and the Deep Basin, in addition to the summer drilling described above.
Please be advised that the forecasts above with respect to capital spending may constitute a "financial outlook" as contemplated by NI 51-102. The purpose of such information is to forecast the anticipated capital spending of the Company for 2010.
Liquidity & Capital Resources
At June 30, 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, current loss on sublease and
associated future tax liabilities $ (2,080)
Long-term debt (21,692)
Bank facilities available 40,000
-------------------------------------------------------------------------
Total capital resources available $ 16,228
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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 June 30, 2010, the Company's ratio of net debt to trailing quarterly operating cash flow was 1.8 to 1.0, which meets the Company's guidelines on capital management (which call for a maximum of 2.0 to 1.0). The Company continues to closely monitor its overall net debt levels and the resulting ratio to ensure proper debt levels are maintained.
Bank Debt
At June 30, 2010 the Company has a $40.0 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 covenants under the terms of this facility. As at June 30, 2010, the Company is in compliance with all covenants in accordance with the terms of the credit facility. The next scheduled review date of the facility is May 31, 2011.
Share Capital
As at June 30, 2010, ProspEx had 57,385,162 common shares (2009 - 57,385,162), no warrants (2009 - 2,016,269), and 5,051,167 options (2009 - 5,060,078) issued and outstanding. Each option, upon exercise, entitles the holder to one common share.
As at July 28, 2010 ProspEx had 57,385,162 common shares, no warrants, and 5,051,167 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 $ - $21,692 $ - $ - $ - $ - $21,692
Building lease 470 1,051 1,356 1,433 358 - 4,668
Processing fees 404 809 640 480 360 57 2,750
Transportation 520 596 140 - - - 1,256
Other 2 - - - - - 2
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total $1,396 $24,148 $2,136 $1,913 $ 718 $ 57 $30,368
-------------------------------------------------------------------------
Off-Balance Sheet Arrangements
The Company has not entered into any off-balance sheet transactions other than previously discussed.
Summary of Quarterly Results
The following table summarizes the quarterly operating statistics of the Company.
Q2 Q1 Q4 Q3
2010 2010 2009 2009
-------------------------------------------------------------------------
Average Daily Production
Natural Gas (mcf/d) 14,996 14,288 11,327 8,906
NGL (bbls/d) 562 583 557 456
Oil (bbls/d) 26 29 32 37
-----------------------------------------
Total (boe/d) 3,086 2,994 2,477 1,978
-----------------------------------------
Operating Netbacks ($/boe)
Price(1) $ 34.05 39.07 35.49 27.61
Royalties (7.49) (5.85) (5.15) (1.21)
Operating costs (7.90) (7.97) (8.72) (8.37)
Transportation (1.50) (1.55) (1.21) (1.12)
-----------------------------------------
Total $ 17.16 23.70 20.41 16.91
-----------------------------------------
E&D Capital Spending ($000's) $ 3,238 7,858 3,988 6,438
Selected Financial Results
($000's, except per share amounts)
Oil and gas revenue $ 9,564 10,526 8,088 5,023
Unrealized financial
instrument (loss) gain (1,058) 2,196 (2) (401)
Net (loss) earnings (1,900) 1,908 (1,231) (3,082)
Basic per share $ (0.03) 0.03 (0.02) (0.05)
Diluted per share $ (0.03) 0.03 (0.02) (0.05)
-------------------------------------------------------------------------
Q2 Q1 Q4 Q3
2009 2009 2008 2008
-------------------------------------------------------------------------
Average Daily Production
Natural Gas (mcf/d) 14,382 17,561 16,868 18,379
NGL (bbls/d) 645 811 719 722
Oil (bbls/d) 47 69 57 65
-----------------------------------------
Total (boe/d) 3,089 3,807 3,587 3,850
-----------------------------------------
Operating Netbacks ($/boe)
Price(1) 26.22 37.25 45.59 55.65
Royalties (1.21) (7.37) (8.18) (12.98)
Operating costs (9.30) (7.16) (4.58) (7.76)
Transportation (0.93) (1.04) (1.00) (0.91)
-----------------------------------------
Total 14.78 21.68 31.83 34.00
-----------------------------------------
E&D Capital Spending ($000's) 1,619 5,641 12,797 12,693
Selected Financial Results
($000's, except per share amounts)
Oil and gas revenue 7,370 12,765 15,046 19,714
Unrealized financial
instrument (loss) gain 310 (828) (363) 8,277
Net (loss) earnings (3,899) (2,225) 487 6,923
Basic per share (0.07) (0.04) 0.01 0.12
Diluted per share (0.07) (0.04) 0.01 0.12
-------------------------------------------------------------------------
(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.
INTERNATIONAL REPORTING STANDARDS
On January 1, 2011 International Financial Reporting Standards ("IFRS") will replace Canadian generally accepted accounting principles ("GAAP") 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 was set up internally to lead the conversion project. The project team, as well as other key finance personnel, has attended industry specific 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. The following areas are expected to change significantly for the Company:
- property plant and equipment ("PP&E"), specifically treatment of
exploration and evaluation costs, depreciation and depletion of
property, plant and equipment and impairment of assets
- asset retirement obligations
- business combinations
- future income taxes
- more extensive presentation and disclosure
Future changes in IFRS prior to adoption may result in other accounting policy changes which could significantly impact the financial statements.
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.
IFRS 1 First Time Adoption of International Financial Reporting Standards provides a number of optional exemptions and mandatory exceptions to the general requirement for full retrospective application. This standard is only applicable to the opening balance sheet of the entity on transition to IFRS.
The following is a discussion of which IFRS 1 exemptions and exceptions the Company is considering using and the policy choices the Company has made or the progress of policy decisions for areas for which a significant change on conversion is anticipated:
Property, Plant and Equipment
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. Under IFRS, costs previously accumulated in the full cost pool are capitalized as exploration and evaluation ("E&E") assets or developing and producing ("D&P") assets or expensed as E&E expenditures.
At transition to IFRS, new accounting policies must be adopted for E&E assets and expenditures and for D&P assets.
- Costs incurred by the Company before acquiring the legal right to
explore in an area, do not meet the definition of an asset under IFRS
and therefore will likely be expensed as E&E expenditures by the
Company as incurred. The Company does not expect these costs to be
significant.
- The Company intends to capitalize as E&E assets, costs for projects
for which technical feasibility and commercial viability has not been
determined but for which the legal right to explore in the area has
been obtained. When the technical feasibility and commercial
viability of the project is determined the costs will be transferred
to D&P assets. The standard does not define technical feasibility and
commercial viability. The Company intends to classify a project as
technically feasible and commercially viable when proved plus
provable reserves are assigned to the project. Unrecoverable costs
associated with a project will likely be expensed. The Company does
not intend to deplete any E&E assets.
- D&P assets will likely be defined as expenditures on projects where
technical feasibility and commercial viability have been determined.
Under IFRS these costs should be capitalized and depleted on a unit
of production basis using proved or proved plus probable reserves
over a component level instead of by one company wide cost center.
The Company intends to use proved plus probable reserves as a basis
for depletion.
Under IFRS, impairment of assets is performed at the cash generating unit ("CGU") level which is a lower level than the country wide test currently required under Canadian GAAP. At this time the Company anticipates between two and four CGUs. Impairment tests may be performed using proved or proved plus probable reserves. The Company intends to test impairment using proved plus probable reserves.
On adoption of IFRS the Company has the option to retroactively restate PP&E or elect under IFRS 1 to measure PP&E at the date of transition at fair value or at the amount determined under Canadian GAAP. The Company will likely measure PP&E at the amount determined under Canadian GAAP. On transition, the PP&E balance will then be reclassified as E&E and D&P assets. The Company will likely first re-classify all E&E assets that are currently included in the PP&E balance on the balance sheet. The remaining PP&E balance will be the opening D&P asset value. The standard allows the Company to allocate the D&P asset balance to CGUs based on reserve volumes or values. The allocation method ProspEx intends to use is the net present value of proved plus probable company interest reserve cash flow values. Once oil and gas assets are allocated to cash generating units they are required to be tested for impairment, at the CGU level. Based on preliminary analysis PP&E will not be impaired on transition.
Decommissioning Liability
The decommissioning liability is currently referred to as asset retirement obligation under Canadian GAAP. IFRS 1 has an election which the Company plans to adopt, whereby the liability is measured at transition in accordance with IAS 37 Provisions, Contingent Liabilities and Contingent Assets, and any difference between that amount and the Canadian GAAP carrying amount of those liabilities at the date of transition is recognized in retained earnings. Based on preliminary calculations the liability will be higher under IFRS as the discount rate used in calculating the liability will likely be a risk free rate as opposed to the credit adjusted risk free rate currently used under Canadian GAAP.
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. The Company's current data gathering and accounting system is capable of obtaining and recording data at a level of detail required for IFRS with slight modifications. Modifications include increasing the level of detail of which costs are tracked and adding new accounts.
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.
The Company must also monitor all changes or anticipated changes in IFRS on an ongoing basis.
Business Activities
ProspEx has reviewed the impact of IFRS on its commodity price risk management practices, debt covenants and compensation arrangements and does not expect IFRS to have any significant changes in these areas.
Internal Control over Financial Reporting and Disclosure Controls and Procedures
Changes may be required to internal controls over financial reporting and disclosure controls and procedures with the implementation of IFRS. The implications will be analyzed once accounting policy choices and implementation plans are finalized.
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 June 30, 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 June 30, 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 second 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:
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($000s) 2010 2009 2010 2009
-------------------------------------------------------------------------
Cash flow from operating
activities $ 4,078 $ (5,251) $ 8,191 $ 3,728
Change in non-cash
working capital (591) 7,726 548 4,468
-----------------------------------------------
Cash flow $ 3,487 $ 2,475 $ 8,739 $ 8,196
-------------------------------------------------------------------------
The following table provides a reconciliation of total net debt for the periods below:
As at As at
June 30, June 30,
($000's) 2010 2009
-------------------------------------------------------------------------
Accounts receivable $ (6,306) $ (6,666)
Prepaid expenses (197) (275)
Accounts payable and accrued liabilities 8,583 9,023
Long-term debt 21,692 20,950
-------------------------------------------------------------------------
Total net debt $ 23,772 $ 23,032
-------------------------------------------------------------------------
-------------------------------------------------------------------------
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, current loss on sublease and associated future tax assets (liabilities).
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)
June 30, December 31,
(Stated in thousands of dollars) 2010 2009
-------------------------------------------------------------------------
Assets
Current assets
Accounts receivable $ 6,306 $ 7,800
Prepaid expenses 197 389
Future income tax asset (note 2) - 27
Fair value of commodity contracts (note 4) 1,045 -
-------------------------
7,548 8,216
Property, plant and equipment, net 147,388 145,939
-------------------------
Total assets $ 154,936 $ 154,155
-------------------------
-------------------------
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 8,583 $ 12,599
Current loss on sublease 234 226
Fair value of commodity contracts (note 4) - 93
Future income tax liability (note 2) 227 -
-------------------------
9,044 12,918
Long-term debt (note 1) 21,692 17,234
Asset retirement obligation 3,653 3,810
Other long-term liabilities 92 198
Future income tax liability (note 2) 5,139 5,160
-------------------------
Total liabilities 39,620 39,320
-------------------------
Shareholders' Equity
Common shares (note 3 a) 90,800 90,800
Contributed surplus (note 3 b) 9,460 8,987
Retained earnings 15,056 15,048
-------------------------
Total shareholders' equity 115,316 114,835
-------------------------
$ 154,936 $ 154,155
-------------------------
-------------------------
Commitments (note 6)
See accompanying notes to consolidated financial statements
ProspEx Resources Ltd.
Consolidated Statements of (Loss) Earnings, Comprehensive (Loss)
Earnings and Retained Earnings
For the periods ended
(unaudited)
Three Three Six Six
months months months months
(Stated in thousands ended ended ended ended
of dollars, except June 30, June 30, June 30, June 30,
per share amounts) 2010 2009 2010 2009
-------------------------------------------------------------------------
Revenue
Oil and gas $ 9,564 $ 7,370 $ 20,090 $ 20,135
Unrealized financial
instrument (loss) gain
(note 4) (1,058) 310 1,138 (517)
Royalties (2,103) (341) (3,680) (2,867)
-----------------------------------------------
6,403 7,339 17,548 16,751
-----------------------------------------------
Expenses
Depletion, depreciation
and accretion 5,141 8,247 9,977 16,988
Operating 2,218 2,613 4,364 5,066
Transportation 420 262 837 619
General and
administrative 684 851 1,424 1,757
Interest and bank charges 351 439 547 755
Stock-based compensation 113 105 237 209
Sublease loss - 524 - 524
-----------------------------------------------
8,927 13,041 17,386 25,918
-----------------------------------------------
(Loss) earnings before
income taxes (2,524) (5,702) 162 (9,167)
Income taxes (note 2)
Future (reduction)
expense (624) (1,803) 154 (3,043)
-----------------------------------------------
Net (loss) earnings and
comprehensive (loss)
earnings for the period (1,900) (3,899) 8 (6,124)
Retained earnings,
beginning of period 16,956 23,260 15,048 25,485
-----------------------------------------------
-----------------------------------------------
Retained earnings,
end of period $ 15,056 $ 19,361 $ 15,056 $ 19,361
-----------------------------------------------
-----------------------------------------------
Net (loss) earnings
per share
Basic $ (0.03) $ (0.07) $ 0.00 $ (0.11)
-----------------------------------------------
-----------------------------------------------
Diluted $ (0.03) $ (0.07) $ 0.00 $ (0.11)
-----------------------------------------------
-----------------------------------------------
See accompanying notes to consolidated financial statements
ProspEx Resources Ltd.
Consolidated Statements of Cash Flows
For the periods ended
(unaudited)
Three Three Six Six
months months months months
ended ended ended ended
(Stated in thousands June 30, June 30, June 30, June 30,
of dollars) 2010 2009 2010 2009
-------------------------------------------------------------------------
Operations
Net (loss) earnings for
the period $ (1,900) $ (3,899) $ 8 $ (6,124)
Items not involving cash
Depletion, depreciation
and accretion 5,141 8,247 9,977 16,988
Stock-based compensation 113 105 237 209
Future income tax
(reduction) expense (624) (1,803) 154 (3,043)
Unrealized financial
instrument loss (gain) 1,058 (310) (1,138) 517
Amortization of rent
inducements (28) - (55) -
Amortization of sublease
loss (56) 524 (111) 524
Asset retirement
expenditures (217) (389) (333) (875)
-----------------------------------------------
3,487 2,475 8,739 8,196
Changes in non-cash
working capital 591 (7,726) (548) (4,468)
-----------------------------------------------
4,078 (5,251) 8,191 3,728
-----------------------------------------------
Financing
Increase (decrease)
in long-term debt 336 (16,521) 4,458 (19,858)
-----------------------------------------------
336 (16,521) 4,458 (19,858)
-----------------------------------------------
Investments
Exploration and
development
expenditures (3,238) (1,619) (11,096) (7,261)
Proceeds on property
disposal 208 26,886 196 28,964
Property acquisition - (1,503) - (1,503)
Other capital
expenditures (21) (4) (21) (7)
-----------------------------------------------
(3,051) 23,760 (10,921) 20,193
Changes in non-cash
working capital (1,363) (1,988) (1,728) (4,063)
-----------------------------------------------
(4,414) 21,772 (12,649) 16,130
-----------------------------------------------
Change in cash - - - -
Cash, beginning of period - - - -
-----------------------------------------------
Cash, end of period $ - $ - $ - $ -
-----------------------------------------------
-----------------------------------------------
Additional cash flow disclosure (note 5)
See accompanying notes to consolidated financial statements
Notes to Consolidated Financial Statements
For the three and six months ended June 30, 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 June 30,
2010 and the results of its operations and cash flows for the three and
six months ended June 30, 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 June 30, 2010 the Company has a $40.0 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 covenants under the terms
of this facility. As at June 30, 2010, the Company is in compliance with
all covenants in accordance with the terms of the credit facility. The
next scheduled review date of the facility is 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 Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($000's) 2010 2009 2010 2009
-------------------------------------------------------------------------
(Loss) earnings before
income taxes $ (2,524) $ (5,702) $ 162 $ (9,167)
Combined statutory
rate (%) 28.0% 29.0% 28.0% 29.0%
-------------------------------------------------------------------------
Computed expected future
income tax (reduction)
expense (707) (1,654) 45 (2,659)
Increase (decrease) in
taxes resulting from:
Stock-based
compensation expensed 31 30 66 60
Effect of change in
tax rate 45 (211) 36 (490)
Other 7 32 7 46
-------------------------------------------------------------------------
Income tax (reduction)
expense $ (624) $ (1,803) $ 154 $ (3,043)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The components of the future income tax liability are as follows:
June 30, December 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Property, plant and equipment $ (5,700) $ (5,900)
Fair value of commodity contracts (293) 27
Asset retirement obligation 913 952
Loss due to leasing arrangements 129 146
Share issue costs 85 142
-------------------------------------------------------------------------
(4,866) (4,633)
Valuation allowance (500) (500)
-------------------------------------------------------------------------
Future income tax liability $ (5,366) $ (5,133)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At June 30, 2010, the Company had estimated tax pools available to reduce
future taxable income of $126.6 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 six months ended June 30,
2010 (2009 - $0.1 million).
3. SHAREHOLDERS' EQUITY
(a) Common Shares & Common Share Performance Warrants Issued
June 30, 2010 June 30, 2009
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Number Number
of Shares/ of Shares/
Warrants Amount Warrants Amount
(000's) ($000's) (000's) ($000's)
-------------------------------------------------------------------------
Common shares
Balance at the beginning
and end of the period 57,385 $ 90,800 57,385 $ 90,802
-----------------------------------------------------------------------
Common share performance
warrants
Balance at the beginning
and end of the period - $ - 2,016 $ 1,233
-----------------------------------------------------------------------
(b) Contributed Surplus
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($000's) 2010 2009 2010 2009
-------------------------------------------------------------------------
Balance at the beginning
of the period $ 9,235 $ 6,965 $ 8,987 $ 6,758
Stock-based compensation 225 209 473 416
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Balance at the end of
the period $ 9,460 $ 7,174 $ 9,460 $ 7,174
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(c) Stock Options
Changes in outstanding stock options are summarized below:
June 30, 2010 June 30, 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
Granted - - 617 0.70
Forfeited (125) 1.92 (717) 3.52
Expired (85) 3.22 - -
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Outstanding at end of period 5,051 $ 2.33 5,060 $ 3.10
-------------------------------------------------------------------------
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The following table summarizes stock options outstanding and exercisable
at June 30, 2010:
Options outstanding Options exercisable
-------------------------------------------------------------------------
Number 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 1,082 4.0 $ 0.66 200 $ 0.70
$0.93 - $1.40 1,407 4.2 $ 1.01 83 $ 1.25
$2.13 - $3.20 250 2.4 $ 3.01 167 $ 3.01
$3.21 - $4.46 2,312 1.7 $ 3.85 2,083 $ 3.89
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5,051 2.9 $ 2.33 2,533 $ 3.49
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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 June 30, 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. During the six months ended June 30, 2010, a total of
$0.2 million (2009 - $0.2 million) of stock-based compensation was
recorded against income and $0.2 million (2009 - $0.2 million) was
capitalized.
(d) Per Share Amounts
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
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Weighted average common
shares basic 57,385,162 57,385,162 57,385,162 57,385,162
Dilutive securities:
Stock options - - 609,536 -
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Diluted 57,385,162 57,385,162 57,994,698 57,385,162
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For the three months ended June 30, 2010, 5,051,167 options and no
warrants (2009 - 5,060,078 options and 2,106,269 warrants) were excluded
from the diluted calculations as they were anti-dilutive. For the six
months ended June 30, 2010, 2,585,001 options were excluded due to their
anti-dilutive impact (2009 - 5,081,483 options and 2,016,269 warrants).
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 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.
June 30, 2010
--------------------------------------------------
Fair Value Level 1 Level 2 Level 3
-------------------------------------------------------------------------
Commodity Contracts 1,045 - 1,045 -
-------------------------------------------------------------------------
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 interest
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 interest receivables are typically collected within
one to three months of the joint interest bill being issued to the
partner. The Company attempts to mitigate the risk from joint interest
receivables by obtaining joint interest partners approval of significant
capital expenditures prior to expenditure. The Company does not typically
obtain collateral from petroleum and natural gas marketers or joint
interest partners; however in certain circumstances, it may elect to cash
call a joint interest partner in advance of the work.
As at June 30, 2010 the Company's receivables consisted of $2.5 million
(December 31, 2009 - $2.7 million) from joint interest partners,
$2.7 million (December 31, 2009 - $3.5 million) of receivables from
petroleum and natural gas marketers and $1.1 million (December 31, 2009 -
$1.6 million) of other receivables. Of the $6.3 million in total accounts
receivable, $0.2 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 June 30, 2010 and did not provide
for any doubtful accounts nor was it required to write-off any
receivables during the quarter ended June 30, 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 June 30, 2010:
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Financial
Liability (less than)
($000's) 1 year 1 - 2 years 2 - 5 years Thereafter
-------------------------------------------------------------------------
Accounts payable and
accrued liabilities $ 8,583 - - -
Long-term debt - 21,692 - -
-------------------------------------------------------------------------
Total $ 8,583 21,692 - -
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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 cannot be
accurately quantified. The Company had no forward exchange rate contracts
in place as at or during the three and six months ended June 30, 2010 and
2009.
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 June 30, 2010:
Type Amount (GJ/day) Term Price ($/GJ at AECO) Type
---- --------------- ---- -------------------- ----
Fixed 1,000 Jul. 1 - Oct. 31, 2010 $5.18 Financial
Fixed 1,000 Jul. 1 - Oct. 31, 2010 $5.385 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $5.00 - $6.16 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $5.00 - $5.90 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $4.90 - $5.63 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $5.00 - $5.95 Financial
Collar 1,000 Jul. 1 - Oct. 31, 2010 $4.75 - $5.86 Financial
Fixed 1,000 Sept. 1 - Oct. 31, 2010 $4.05 Financial
Fixed 1,000 Sept. 1 - Oct. 31, 2010 $3.96 Financial
The contracts in place during the three months ended June 30, 2010
resulted in an unrealized loss of $1.1 million (June 30, 2009 -
$0.3 million unrealized gain) and a realized gain of $0.9 million
(June 30, 2009 - no realized gain or loss). During the six months ended
June 30, 2010 the contracts in place resulted an unrealized gain of
$1.1 million (2009 - $0.5 million unrealized loss) and a realized gain
of $0.8 million (2009 - $1.3 million realized gain)
With respect to commodity prices, during the three months ended June 30,
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 decrease of
$0.1 million (2009 - no production dedicated). A one dollar decrease in
the price per GJ of natural gas on the same production would have
increased net earnings after taxes for the three months ended June 30,
2010 by $0.1 million (2009 - no production dedicated). 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 and six months ended
June 30, 2010. For the three and six months ended June 30, 2010, a
difference in the interest rate of 1% would change net earnings after tax
by an estimated $0.1 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.
June 30, December 31,
($000's) 2010 2009
-------------------------------------------------------------------------
Shareholders' equity $ 115,316 $ 114,835
Long-term debt 21,692 17,234
Working capital deficiency excluding fair
value of commodity contracts, current loss
on sublease and associated future taxes 2,080 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 net debt, as
defined as long term debt less working capital (or plus working capital
deficiency) excluding unrealized financial instrument gain (loss),
current loss on sublease and associated future taxes; 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 June 30, 2010 the Company's ratio of net debt to annualized
operating cash flow was 1.7 to 1.0, and compares to the annual 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.
The bank debt facility has no restrictions other than the limitation of
borrowing under the facility on an annual basis and an adjusted working
capital covenant ratio of 1.0 to 1.0. As at June 30, 2010, the Company is
in compliance with all bank facility requirements.
There have been no changes to the Company's capital management strategy
during the quarter ended June 30, 2010.
5. ADDITIONAL DISCLOSURES
Interest and Taxes Paid
Net cash interest paid during the quarter was $0.2 million (2009 -
$0.1 million). Cash taxes paid during the period was $nil (2009 - $nil).
On a year to date basis, net cash interest paid to June 30, 2010 was
$0.4 million (2009 - $0.5 million). Year to date cash taxes paid to
June 30, 2010 was $nil (2009 - $nil).
6. COMMITMENTS
The Company has committed to certain future payments as follows:
Payments due There-
($000's) 2010 2011 2012 2013 2014 after Total
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Long-term debt $ - $21,692 $ - $ - $ - $ - $21,692
Building lease 470 1,051 1,356 1,433 358 - 4,668
Processing fees 404 809 640 480 360 57 2,750
Transportation 520 596 140 - - - 1,256
Other 2 - - - - - 2
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Total $1,396 $24,148 $2,136 $1,913 $ 718 $ 57 $30,368
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%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.
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