CALGARY, ALBERTA--(Marketwire - Aug. 12, 2009) - Zargon Energy Trust ZAR ZOG
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FINANCIAL & OPERATING HIGHLIGHTS
Three Months Ended Six Months Ended
June 30, June 30,
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Percent Percent
(unaudited) 2009 2008 Change 2009 2008 Change
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Financial
Income and Investments
($ millions)
Petroleum and natural gas
revenue 35.84 69.66 (49) 67.82 121.90 (44)
Funds flow from operating
activities 20.92 32.02 (35) 38.77 56.77 (32)
Cash flows from operating
activities 21.94 36.44 (40) 37.67 51.71 (27)
Cash distributions 11.26 9.71 16 21.30 19.26 11
Net earnings/(losses) (2.55) (4.51) 43 (2.19) 0.04 (5,068)
Net capital expenditures 48.96 26.28 86 62.40 85.89 (27)
Per Unit, Diluted
Funds flow from operating
activities ($/unit) 0.91 1.55 (41) 1.76 2.78 (37)
Cash flows from operating
activities ($/unit) 0.95 1.76 (46) 1.71 2.53 (32)
Net earnings/(losses)
($/unit) (0.13) (0.25) 48 (0.11) - -
Cash Distributions
($/trust unit) 0.54 0.54 - 1.08 1.08 -
Balance Sheet at Period
End ($ millions)
Property and equipment,
net 422.73 380.18 11
Bank debt 70.43 85.45 (18)
Unitholders' equity 255.57 166.86 53
Total Units Outstanding at
Period End (millions) 25.28 20.94 21
Operating
Average Daily Production
Oil and liquids (bbl/d) 4,780 4,249 12 4,671 4,210 11
Natural gas (mmcf/d) 28.44 29.94 (5) 28.18 29.50 (4)
Equivalent (boe/d) 9,520 9,239 3 9,368 9,127 3
Equivalent per million
trust units (boe/d) 413 447 (8) 423 446 (5)
Average Selling Price
(before the impact of
financial risk management
contracts)
Oil and liquids ($/bbl) 59.95 111.58 (46) 51.71 98.38 (47)
Natural gas ($/mcf) 3.77 9.73 (61) 4.73 8.66 (45)
Wells Drilled, Net 3.0 5.1 (41) 10.4 14.3 (27)
Undeveloped Land at Period
End (thousand net acres) 533 462 15
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Notes:
Throughout this report, the calculation of barrels of oil equivalent ("boe") is based on the conversion ratio that six thousand cubic feet of natural gas is equivalent to one barrel of oil. For a further discussion about this term, refer to the Management's Discussion and Analysis section in this report.
For net capital expenditures, amounts include capital expenditures acquired for cash, equity issuances, acquisition costs and net debt assumed on corporate acquisitions.
Funds flow from operating activities is a non-GAAP term that represents net earnings/losses and asset retirement expenditures except for non-cash items. For a further discussion about this term, refer to the Management's Discussion and Analysis section in this report.
Total units outstanding include trust units plus exchangeable shares outstanding at period end. The exchangeable shares are converted at the exchange ratio at the end of the period.
Average daily production per million trust units is calculated using the weighted average number of units outstanding during the period plus the weighted average number of exchangeable shares outstanding for the period converted at the average exchange ratio for the period.
FINANCIAL & OPERATING HIGHLIGHTS
Zargon Energy Trust is pleased to report its financial results for the second quarter of 2009. Funds flow from operating activities was $20.92 million ($0.91 per diluted trust unit) in the 2009 second quarter compared with $17.85 million ($0.84 per diluted trust unit) in the 2009 first quarter and $32.02 million ($1.55 per diluted trust unit) in the 2008 second quarter.
Highlights from the three and six months ended June 30, 2009, are noted below:
- Second quarter 2009 production averaged 9,520 barrels of oil equivalent per day, three percent above both the preceding quarter and the corresponding quarter of 2008. Higher second quarter production volumes were primarily due to the additional volumes provided by the acquisition of Masters Energy Inc. ("Masters") which offset natural declines, the shut-in of selected high cost natural gas properties and weather related outages during the quarter. For the second quarter of 2009, Zargon's production averaged 413 barrels of oil equivalent per day per million trust units outstanding compared to 432 barrels of oil equivalent per day per million trust units outstanding for the prior quarter and 447 barrels of oil equivalent per day per million trust units outstanding in the corresponding quarter of 2008.
- Revenue and funds flow from operating activities in the 2009 second quarter increased 12 percent and 17 percent, respectively, from the prior quarter. Realized oil prices increased 40 percent and realized natural gas prices decreased 34 percent from the prior quarter. Realized risk management gains decreased two percent from the prior quarter.
- The Trust declared three monthly cash distributions of $0.18 per trust unit in the second quarter of 2009 for a total of $11.26 million. These cash distributions were equivalent to a payout ratio of 59 percent of the Trust's second quarter funds flow from operating activities on a diluted trust unit basis and, after considering the effect of the exchangeable shares not receiving distributions, the distributions amounted to 54 percent of funds flow from operating activities.
- The Trust's second quarter exploration and development capital expenditures (excluding property acquisitions and dispositions) decreased 33 percent from the prior quarter to $8.56 million primarily as a result of reduced drilling, completions and equipping of wells.
- Due in part to the proceeds received from the June issuance of trust units, debt net of working capital (excluding unrealized risk management assets/liabilities and future income taxes) decreased 16 percent from the prior quarter to $77.47 million at June 30, 2009, which represents approximately 43 percent of the Trust's available credit facilities at June 30, 2009. The Trust's balance sheet remains strong with a debt net of working capital to annualized funds flow from operating activities ratio of 1.0 times.
- On April 29, 2009, Zargon closed the acquisition of Masters for a total consideration of approximately 1.475 million Zargon trust units, $5.70 million in cash and the assumption of approximately $13.29 million of net debt (including adjustments and transactions costs) for a total transaction value of approximately $40.03 million.
- On June 5, 2009, the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of issue costs).
- On July 27, 2009, the Trust amended and renewed its syndicated committed credit facilities of $180 million. These facilities are available for general corporate purposes and the acquisition of oil and natural gas properties.
- On July 28, 2009, the Trust announced the proposed acquisition of Churchill Energy Inc. ("Churchill"), which is expected to be completed in late September, 2009. The proposed transaction is valued at approximately $15.00 million, including the assumption of approximately $5.80 million of net debt (including adjustments and transaction costs). Churchill shareholders may elect to receive either 0.01363 trust units or $0.22 cash for each Churchill common share, subject to a maximum of $4.60 million cash. Churchill is currently producing approximately 400 barrels of oil equivalent per day primarily from its operated Grand Forks, Brazeau and Jarrow/Killam properties in Alberta.
Production (1)
Oil and liquids production averaged 4,780 barrels per day in the 2009 second quarter, a five percent increase from the preceding quarter and a 12 percent increase from the corresponding 2008 quarter. The increase in production volumes was primarily due to the acquisition of Masters which offset natural declines and the impact from Williston Basin spring access related shut-ins. Further oil production increases are anticipated for the balance of 2009 with the addition of volumes from the recent drilling of wells at Steelman in the Williston Basin and Taber in the Alberta Plains.
Natural gas production volumes in the second quarter of 2009 averaged 28.44 million cubic feet per day, a two percent increase from the previous quarter and a five percent decrease from the corresponding period of 2008. The second quarter 2009 natural gas production increased primarily due to the acquisition of Masters which offset natural declines, facility and processing plant maintenance related outages and the shut-in of selected high cost natural gas properties. For the remainder of the year, we anticipate that the Trust's natural gas production volumes will show moderate declines, as we have restricted capital to our natural gas development business during this period of very low natural gas prices and netbacks.
Capital Expenditures (1)
Zargon's second quarter field capital program totalled $8.56 million, a 25 percent decrease from the 2008 second quarter field capital expenditures and a 33 percent decrease from the prior quarter. During the quarter, Zargon drilled three gross wells (3.0 net) that resulted in 3.0 net oil wells for a 100 percent success ratio. This oil exploitation focused drilling program included one Taber horizontal well in the Alberta Plains and two Steelman horizontal wells in the Williston Basin.
For the second half of 2009, Zargon is planning on an oil exploitation focused drilling program that will be primarily targeted on opportunities in the Williston Basin, which will include five Steelman Frobisher oil exploitation horizontal wells along with three additional horizontal wells at Fertile (Torquay/Bakken), Elswick and Manor. At Taber in the Alberta Plains, we will also be following up on our successful second quarter exploitation location with the drilling of two horizontal wells. With success, two additional Taber horizontal wells will be drilled prior to year end. With the continuation of low natural gas prices, we are proceeding cautiously with our natural gas programs and as a result, three Alberta Plains Jarrow natural gas wells that were planned to be drilled this summer have been deferred until this fall. In West Central Alberta, we are currently planning on proceeding with the drilling of one Pembina natural gas exploration target and one step-out natural gas location at Kakut in the Peace River Arch area.
Since spring break up, we have had good results with our Williston Basin oil exploitation program where we have drilled three Steelman Frobisher horizontal wells and one Elswick horizontal well. Initial results are encouraging and we are anticipating average initial production rates in excess of 100 barrels per day per well.
Over the last few quarters, Zargon has successfully redirected its business from a conventional natural gas exploration focus to an increased emphasis on exploitation enabled by periodic accretive acquisitions and reservoir management. Specifically, we have made good progress with our oil exploitation initiatives as evidenced by our recent Williston Basin Frobisher programs and last year's corporate acquisitions of Rival Energy Ltd. and Newpact Energy Corp., this spring's corporate acquisition of Masters and now the recently announced corporate acquisition of Churchill. Furthermore, we continue to make good progress with our detailed technical review of our Little Bow tertiary (Alkaline Surfactant Polymer) oil recovery initiative and look forward to finalizing our plans for this Southern Alberta opportunity by the first quarter of 2010.
Conversely, in recent months very low natural gas prices and netbacks have caused Zargon to further restrict its natural gas focused drilling. As a result of these trends, Zargon's production base is becoming more oil weighted and is expected to reach a 53 percent oil weighting (6:1 equivalency) by the end of this year, up from the 43 percent average oil weighting in calendar 2007.
In the second quarter of 2009, the purchase of 10 thousand net acres of Crown lands at an average price of $31 per acre and the addition of approximately 108 thousand net acres from the Masters acquisition, allowed Zargon to increase its quarter end undeveloped land inventory to 533 thousand net acres, up 102 thousand net acres from the balance reported at the end of the first quarter of 2009. For the remainder of the year, Zargon will continue to be an active participant at Alberta Crown land sales during this period of low Crown land sale costs.
Zargon continues to take advantage of the industry's current lower property and corporate acquisition costs with the announcement and closing of the acquisition of Masters and also with the announcement of the acquisition of Churchill which is expected to close in late September, 2009. During this period of opportunity, Zargon will continue to use its strong balance sheet and solid cash flows augmented by substantial hedge gains along with the proceeds from the recent issuance of trust units to pursue additional property and corporate acquisitions.
Guidance (1)
In the May 12, 2009 press release announcing the first quarter 2009 results, Zargon provided updated production guidance of 9,500 barrels of oil equivalent per day for the second quarter of 2009, and then 10,000 barrels of oil equivalent per day for the remainder of 2009. Consistent with guidance, Zargon's production averaged 9,520 barrels of oil equivalent in the second quarter. Production for the remainder of the year is now anticipated to average 9,800 barrels of oil equivalent per day (not including volumes from the pending acquisition of Churchill). This new guidance reflects the impact of continued natural gas declines and, in selected cases, natural gas shut-ins of marginal properties. These declines are being mostly offset by new exploitation oil volumes coming from our horizontal drilling programs. This guidance continues to be premised on the previously announced 2009 field capital budget of $37 million which has now been mostly redirected for the remainder of the year to oil exploitation projects, primarily in the Williston Basin.
Zargon continues to be well positioned during this current period of lower commodity prices (particularly for natural gas) with a continued strong balance sheet, attractive commodity hedge position and an inventory of promising opportunities that has recently been augmented by corporate acquisitions. We are pleased that our historical conservative hedging, debt and distribution policies have enabled our organization to maintain the current monthly $0.18 per unit distribution for 45 consecutive months. Going forward, Zargon will continue with its disciplined approach pertaining to the matching of our cash flow sources with our distributions and/or field capital and acquisition expenditure uses. To date, during this commodity price downturn, we have been able to maintain distributions primarily due to our substantial 2009 positive hedges and the strength of the forward commodity price strip which indicates improved pre-hedge cash flows in 2010. As we move towards December 2010, we will continue to carefully balance our projected cash flows with the competing uses for our cash resources, while recognizing that Zargon remains committed to our partial cash flow distributing model both before and after the trust sunset date.
(1) Please see comments on "Forward-Looking Statements" in the Management's Discussion and Analysis section in this report.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Management's discussion and analysis ("MD&A") is a review of Zargon Energy Trust's 2009 second quarter financial results and should be read in conjunction with the unaudited interim consolidated financial statements for the three and six months ended June 30, 2009 and the audited consolidated financial statements and related notes for the year ended December 31, 2008. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP"). All amounts are in Canadian dollars unless otherwise noted. All references to "Zargon" or the "Trust" refer to Zargon Energy Trust and all references to the "Company" refer to Zargon Oil & Gas Ltd.
In the MD&A, reserves and production are commonly stated in barrels of oil equivalent ("boe") on the basis that six thousand cubic feet of natural gas is equivalent to one barrel of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalent conversion method primarily applicable to the burner tip and does not represent a value equivalent at the wellhead.
The following are descriptions of non-GAAP measures used in this MD&A:
- The MD&A contains the term "funds flow from operating activities" ("funds flow"), which should not be considered an alternative to, or more meaningful than, "cash flows from operating activities" as determined in accordance with Canadian GAAP as an indicator of the Trust's financial performance. This term does not have any standardized meaning as prescribed by GAAP and, therefore, the Trust's determination of funds flow from operating activities may not be comparable to that reported by other trusts. The reconciliation between cash flows from operating activities and funds flow from operating activities can be found in the table below and in the consolidated statements of cash flows in the consolidated financial statements. The Trust evaluates its performance based on net earnings and funds flow from operating activities. The Trust considers funds flow from operating activities to be a key measure as it demonstrates the Trust's ability to generate the cash necessary to pay distributions, repay debt and to fund future capital investment. It is also used by research analysts to value and compare oil and gas trusts, and it is frequently included in published research when providing investment recommendations. Funds flow from operating activities per unit is calculated using the diluted weighted average number of units for the period.
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Funds Flow from Operating Activities Reconciliation
Three Months Ended Six Months Ended
June 30, June 30,
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($ millions) 2009 2008 2009 2008
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Cash flows from operating activities 21.94 36.44 37.67 51.71
Changes in non-cash operating
working capital (1.02) (4.42) 1.10 5.06
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Funds flow from operating activities 20.92 32.02 38.77 56.77
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- The Trust also uses the term "debt net of working capital" or "net debt". Debt net of working capital, as presented, does not have any standardized meaning prescribed by Canadian GAAP and may not be comparable with the calculation of similar measures for other entities. Debt net of working capital, as used by the Trust, is calculated as bank debt and any working capital deficit excluding unrealized risk management assets/liabilities and future income taxes.
- Operating netbacks per boe equal total petroleum and natural gas revenue per boe adjusted for realized risk management gains and/or losses per boe, royalties per boe and production costs per boe. Operating netbacks are a useful measure to compare the Trust's operations with those of its peers.
- Funds flow netbacks per boe are calculated as operating netbacks less general and administrative expenses per boe, interest and financing charges per boe, asset retirement expenditures per boe and current income taxes per boe. Funds flow netbacks are a useful measure to compare the Trust's operations with those of its peers.
References to "production volumes" or "production" in this document refer to sales volumes.
Forward-Looking Statements - This document offers our assessment of Zargon's future plans and operations as at August 12, 2009, and contains forward-looking statements including:
- our expectations for production referred to under the heading "Financial & Operating Highlights";
- our expectations for capital expenditures referred to under the heading "Financial & Operating Highlights";
- our expectations for the timing of the closing, consideration and addition of production related to the proposed acquisition of Churchill Energy Inc. referred to under the heading "Financial & Operating Highlights" and "Corporate Acquisitions";
- our expectations for royalties referred to under the heading "Financial Analysis";
- our expectations for production costs referred to under the heading "Financial Analysis";
- our expectations for interest expenses referred to under the heading "Financial Analysis";
- our expectations for current taxes referred to under the headings "Financial Analysis";
- our distribution policy referred to under the headings "Financial & Operating Highlights" and "Liquidity and Capital Resources";
- our expected sources of funds for distributions and capital expenditures referred to under the headings "Liquidity and Capital Resources" and "Financial & Operating Highlights"; and
- our expectations for future commodity pricing and operating results referred to under the headings "Financial & Operating Highlights" and "Outlook".
Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe" and similar expressions (including the negatives thereof). By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including such as those relating to results of operations and financial condition, general economic conditions, industry conditions, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel. Risks are described in more detail in our Annual Information Form, which is available on our website and at www.sedar.com. Forward-looking statements are provided to allow investors to have a greater understanding of our business.
You are cautioned that the assumptions, including among other things, future oil and natural gas prices; future capital expenditure levels; future production levels; future exchange rates; the cost of developing and expanding our assets; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition, our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and acquisition activities used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is that Zargon disclaims, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
This MD&A has been prepared as of August 12, 2009.
SUMMARY OF SIGNIFICANT EVENTS IN THE SECOND QUARTER
- During the second quarter of 2009, the Trust realized funds flow from operating activities of $20.92 million and declared total distributions of $11.26 million ($0.54 per trust unit) to unitholders. For Canadian income tax purposes, the distributions are currently estimated to be 100 percent taxable income to unitholders.
- Average field prices received (before the impact of financial risk management contracts) for oil and liquids and for natural gas increased 40 percent to $59.95 per barrel and decreased 34 percent to $3.77 per thousand cubic feet, respectively, compared to the first quarter of 2009.
- Second quarter production volumes were 9,520 barrels of oil equivalent per day, a three percent increase from the first quarter 2009 production levels.
- During the second quarter of 2009, the Trust drilled three gross wells (3.0 net) with a 100 percent success rate. Total field exploration and development capital expenditures (excluding property acquisitions and dispositions) were $8.56 million for the quarter compared to $12.78 million for the prior quarter.
- The Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets/liabilities and future income taxes) of $77.47 million, which represents approximately 43 percent of the Trust's available credit facilities at June 30, 2009.
- On April 29, 2009, Zargon closed the Arrangement Agreement to acquire all the issued and outstanding common shares of Masters Energy Inc. ("Masters") for a total consideration of approximately 1.475 million Zargon trust units, $5.70 million in cash and the assumption of approximately $13.29 million of net debt (including adjustments and transactions costs) for a total transaction value of approximately $40.03 million. This acquisition brought 1,230 barrels of oil equivalent per day of production along with a significant Alkaline Surfactant Polymer (ASP) tertiary oil recovery opportunity at the Little Bow oil property in Southern Alberta.
- On June 5, 2009, the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of equity issuance costs).
- On July 27, 2009, the Trust amended and renewed its syndicated committed credit facilities of $180 million. These facilities are available for general corporate purposes and the acquisition of oil and natural gas properties.
- On July 28, 2009, the Trust announced the proposed acquisition of Churchill Energy Inc. ("Churchill"), which is expected to be completed in late September, 2009. The proposed transaction is valued at approximately $15.00 million, including the assumption of approximately $5.80 million of net debt (including adjustments and transaction costs). Churchill shareholders may elect to receive either 0.01363 trust units or $0.22 cash for each Churchill common share, subject to a maximum of $4.60 million cash. Churchill is currently producing approximately 400 barrels of oil equivalent per day primarily from the operated Grand Forks, Brazeau and Jarrow/Killam properties in Alberta.
FINANCIAL ANALYSIS
Second quarter 2009 revenue of $35.84 million was 12 percent above the $31.98 million in the first quarter of 2009 and 49 percent below the $69.66 million in the second quarter of 2008. A 40 percent increase in oil and liquids prices received and a three percent increase in production volumes were the primary reasons for the increased revenues when compared to the prior quarter amounts. Second quarter 2009 realized oil and liquids field prices averaged $59.95 per barrel before the impact of financial risk management contracts and were 40 percent higher than the preceding quarter's $42.97 per barrel and were 46 percent lower than the $111.58 per barrel recorded in the 2008 second quarter. Zargon's crude oil field price differential from the Edmonton par price decreased to $5.95 per barrel in the second quarter of 2009 compared to $6.55 per barrel in the first quarter of 2009. Natural gas field prices received averaged $3.77 per thousand cubic feet before the impact of financial risk management contracts in the second quarter of 2009 ($3.22 per thousand cubic feet before the impact of physical and financial risk management contracts), a 34 percent decrease from the preceding quarter levels and 61 percent below the 2008 second quarter prices. Zargon's realized field prices differ from the benchmark AECO average daily price due to a combination of fixed price physical contracts (see note 11 to the interim unaudited consolidated financial statements) and from the impact of Zargon receiving AECO monthly index pricing for a portion of its natural gas production.
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Pricing
Three Months Ended Six Months Ended
June 30, June 30,
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Percent Percent
Average for the period 2009 2008 Change 2009 2008 Change
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Natural Gas:
NYMEX average daily spot
price ($US/mmbtu) 3.71 11.38 (67) 4.14 10.02 (59)
AECO average daily spot
price ($Cdn/mmbtu) 3.46 10.22 (66) 4.20 9.10 (54)
Zargon realized field
price before the impact
of financial risk
management contracts
($Cdn/mcf) 3.77 9.73 (61) 4.73 8.66 (45)
Zargon realized field
price before the impact
of physical and
financial risk management
contracts ($Cdn/mcf) 3.22 10.04 (68) 4.02 8.90 (55)
Zargon realized field
price after the impact
of physical and financial
risk management contracts
($Cdn/mcf) 4.20 9.32 (55) 5.25 8.62 (39)
Zargon realized natural
gas field price
differential/(premium)(1) (0.31) 0.49 (0.53) 0.44
Zargon realized natural
gas field price
differential before the
impact of physical and
financial risk management
contracts 0.24 0.18 0.18 0.20
Crude Oil:
WTI ($US/bbl) 59.62 123.98 (52) 51.35 110.92 (54)
Edmonton par price
($Cdn/bbl) 65.90 126.07 (48) 57.71 111.79 (48)
Zargon realized field
price before the impact
of financial risk
management contracts
($Cdn/bbl) 59.95 111.58 (46) 51.71 98.38 (47)
Zargon realized field
price after the impact
of financial risk
management contracts
($Cdn/bbl) 74.51 91.37 (18) 66.36 83.26 (20)
Zargon realized oil field
price differential (2) 5.95 14.49 6.00 13.41
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(1) Calculated as Zargon's realized field price before the impact of
financial risk management contracts ($Cdn/mcf) as compared to AECO
average daily spot price ($Cdn/mmbtu). Note: premiums may occur as a
result of the realization of fixed price physical contracts and the
impact of Zargon receiving AECO monthly index pricing for a portion of
its natural gas production.
(2) Calculated as Zargon's realized field price before the impact of
financial risk management contracts ($Cdn/bbl) as compared to Edmonton
par price ($Cdn/bbl).
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Natural gas production volumes increased by two percent in the second quarter of 2009 to 28.44 million cubic feet per day from 27.92 million cubic feet per day in the first quarter of 2009 and were five percent lower than the 2008 second quarter. When compared to the prior quarter, the 2009 second quarter increase in natural gas production volumes were primarily a result of 2.28 million cubic feet per day of production volume additions from the April 29, 2009 acquisition of Masters, which offset reduced production from the shut-in of high cost natural gas properties, facility and processing plant maintenance related outages and natural production declines. Oil and liquids production during the second quarter of 2009 was 4,780 barrels per day, which is five percent above the 2009 first quarter rate of 4,560 barrels per day and 12 percent above the second quarter of 2008 level. The year-over-year increase in oil and liquids production volumes was also primarily due to the post acquisition contribution of 407 barrels of oil per day of production volume additions coming from the Masters properties. On a barrel of oil equivalent basis, Zargon produced 9,520 barrels of oil equivalent per day in the second quarter of 2009, which represents a three percent increase from the 9,213 barrels of oil equivalent per day in the first quarter of 2009 and a three percent increase when compared to the second quarter of 2008.
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Production by Core Area
Three Months
Ended June 30, 2009 2008
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Oil and Natural Oil and Natural
Liquids Gas Equivalents Liquids Gas Equivalents
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)
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Alberta Plains 1,761 17.09 4,609 1,271 20.27 4,650
West Central
Alberta 366 10.76 2,160 265 9.08 1,778
Williston
Basin 2,653 0.59 2,751 2,713 0.59 2,811
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4,780 28.44 9,520 4,249 29.94 9,239
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Six Months
Ended June 30, 2009 2008
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Oil and Natural Oil and Natural
Liquids Gas Equivalents Liquids Gas Equivalents
(bbl/d) (mmcf/d) (boe/d) (bbl/d) (mmcf/d) (boe/d)
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Alberta Plains 1,578 17.12 4,431 1,202 19.81 4,504
West Central
Alberta 373 10.55 2,131 253 9.19 1,785
Williston
Basin 2,720 0.51 2,806 2,755 0.50 2,838
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4,671 28.18 9,368 4,210 29.50 9,127
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Zargon's commodity price risk management policy, which is approved by the Board of Directors, allows the use of forward sales, costless collars and other instruments up to a 24 month term and approximately 30 percent of oil and natural gas working interest production in order to partially offset the effects of commodity price fluctuations. Zargon's management considers financial risk management contracts to be effective on an economic basis, but has decided not to designate these contracts as hedges for accounting purposes and, accordingly, for these contracts, an unrealized gain or loss is recorded based on the fair value (mark-to-market) of the contracts at the period end.
Specifically, in the 2009 second quarter, relatively lower oil and natural gas prices brought about a net realized financial risk management gain totalling $7.45 million, consisting of a $1.12 million gain on natural gas contracts and a $6.33 million gain on oil contracts (foreign exchange contracts are considered in conjunction with the oil contracts), that compares to a $7.63 million realized net gain in the first quarter of 2009 and a $8.95 million realized net loss in the second quarter of 2008.
The 2009 second quarter unrealized risk management loss resulted from oil contract (including related foreign exchange contract) losses of $13.21 million, and by unrealized risk management natural gas contract losses of $0.44 million resulting in a total loss of $13.65 million for the quarter, which compares to a net $6.17 million loss for the 2009 first quarter and a net $29.63 million loss in the second quarter of 2008. These non-cash unrealized risk management gains or losses are generated by the change over the reporting period in the mark-to-market valuation of Zargon's risk management contracts. Recent volatility in commodity prices has resulted in significant fluctuations in the mark-to-market amount of unrealized risk management assets and liabilities. The period-over-period changes in these valuations directly impact net earnings/losses. Zargon's commodity risk management positions are fully described in note 11 to the unaudited consolidated interim financial statements.
Royalties, inclusive of the Saskatchewan Resource Surcharge, totalled $5.99 million for the second quarter of 2009, an increase of seven percent from the $5.59 million preceding quarter expense and a decrease of 57 percent from $14.04 million in the second quarter of 2008. The variations in royalty rates generally track changes in production volumes and prices. As a percentage of petroleum and natural gas revenue, royalty rates in 2008 tended to move in a relatively narrow range from 20 to 21 percent and were 20.2 percent in the second quarter of 2008. Commencing in 2009, the oil and natural gas royalty structure changed for Alberta production volumes (as disclosed in our 2008 Annual Financial Report). Reflecting lower commodity prices and the modified royalty structure, on a consolidated basis, the second quarter of 2009 royalties resulted in a rate of 16.7 percent (17.4 percent excluding revenue that does not attract royalty expenses) which compared to 17.5 percent (18.8 percent excluding revenue that does not attract royalty expenses) in the first quarter of 2009. For the remainder of the year Zargon expects that its royalty rate will range from 18 to 20, but will ultimately depend on the actual price received for our production.
On a unit of production basis, production costs of $13.08 per barrel of oil equivalent in the second quarter of 2009 compares with $13.56 per barrel of oil equivalent in the preceding quarter and $11.22 per barrel of oil equivalent in the second quarter of 2008. The decrease in the 2009 second quarter costs (on a unit of production basis) primarily relates to first quarter 2009 weather related expenses and prior period adjustments. Despite the addition of the slightly more expensive Masters properties, Zargon anticipates that its production costs can be maintained in the $13.00 to $13.50 range for the remainder of the year.
/T/
Operating Netbacks
Three Months Ended June 30, 2009 2008
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Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 59.95 3.77 111.58 9.73
Realized risk management gain/(loss) 14.56 0.43 (20.22) (0.41)
Royalties (11.94) (0.30) (22.71) (1.93)
Production costs (13.69) (2.07) (13.93) (1.48)
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Operating netbacks 48.88 1.83 54.72 5.91
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Six Months Ended June 30, 2009 2008
----------------------------------------------------------------------------
Oil and Natural Oil and Natural
Liquids Gas Liquids Gas
($/bbl) ($/mcf) ($/bbl) ($/mcf)
----------------------------------------------------------------------------
Production revenue 51.71 4.73 98.38 8.66
Realized risk management gain/(loss) 14.65 0.53 (15.12) (0.04)
Royalties (10.15) (0.58) (20.05) (1.75)
Production costs (14.64) (2.00) (13.76) (1.50)
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Operating netbacks 41.57 2.68 49.45 5.37
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/T/
Measured on a unit of production basis, general and administrative expenses (net of recoveries) were $4.18 per barrel of oil equivalent in the first half of 2009 compared to $2.92 in the first half of 2008 and $3.08 for the twelve month period of 2008. The year-over-year increase in general and administrative expenses on a per unit of production basis are primarily due to additional office lease costs and the costs related to the expansion of Zargon's technical staff and consultants, as Zargon repositions itself for its renewed exploitation and acquisition initiatives. Also included in the 2009 first six months are one-time employment related charges that increased the general and administrative expenses by approximately $0.37 per barrel of oil equivalent.
Expensing of unit-based compensation in the second quarter of 2009 was $0.28 million, an eight percent increase from the second quarter of 2008 and a 97 percent increase from the prior quarter. The increase is a result of 0.38 million unit rights granted on May 20, 2009 at a price of $15.56 per unit right pursuant to the Trust's new unit rights incentive plan as approved at Zargon's Annual and Special meeting of Unitholders held on April 22, 2009.
Zargon's borrowings are through its syndicated bank credit facilities. Interest and financing charges on these facilities in the 2009 second quarter were $0.49 million, $0.13 million lower than the previous quarter amount of $0.62 million and a decrease of $0.87 million from $1.36 million in the second quarter of 2008. This year-over-year decrease is primarily due to a decrease in average bank debt levels and declining interest rates. In particular bank debt levels were decreased in June 2009, when the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of equity issuance expenses). Zargon's current available syndicated committed credit facilities and borrowing base are $180 million, with approximately 61 percent unutilized at June 30, 2009.
On July 27, 2009, Zargon amended and renewed its syndicated committed credit facilities of $180 million. The next renewal date is June 29, 2010. These facilities continue to be available for general corporate purposes and the potential acquisition of oil and natural gas properties. For the remainder of 2009 through to the 2010 renewal, Zargon's borrowing costs will be higher as general debt pricing, standby fees and extension fees have risen considerably in the current economic environment. Interest rates fluctuate under the syndicated facilities with Canadian prime, US prime, and US base rates plus an applicable margin between 125 basis points and 275 basis points (2008 - zero and 32.5 basis points, respectively), as well as with Canadian banker's acceptance and LIBOR rates plus an applicable margin between 275 basis points and 425 basis points (2008 - 97.5 and 157.5 basis points, respectively). Credit facility extension fees of approximately $0.58 million were paid at the July 27, 2009 renewal and will be reflected in the 2009 third quarter interest expense.
Current income taxes for the 2009 second quarter were $0.43 million, and related primarily to the United States operations. When compared to prior periods, current income taxes decreased $0.56 million from the 2008 second quarter and decreased $0.04 million relative to the first quarter of 2009. The decreased 2009 taxable income is primarily due to reduced oil prices. A reduced capital program for this geographic region tends to result in reduced tax pool claims and, therefore, continues to cause minimal levels of United States taxes. Provided that oil prices remain low, a similar level of United States current income taxes is predicted for the remaining quarters of 2009. Total corporate tax pools as at June 30, 2009, are approximately $235 million, which represents an increase of 25 percent from the comparable $188 million of tax pools available to Zargon at December 31, 2008, primarily a result of the tax pools acquired as part of the recent Masters acquisition.
/T/
Trust Netbacks
Three Months Ended Six Months Ended
June 30, June 30,
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($/boe) 2009 2008 2009 2008
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Petroleum and natural gas revenue 41.37 82.85 40.00 73.38
Realized risk management gain/(loss) 8.60 (10.64) 8.89 (7.11)
Royalties (6.92) (16.70) (6.83) (14.90)
Production costs (13.08) (11.22) (13.32) (11.19)
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Operating netbacks 29.97 44.29 28.74 40.18
General and administrative (4.29) (3.10) (4.18) (2.92)
Interest and financing charges (0.57) (1.61) (0.66) (1.62)
Asset retirement expenditures (0.47) (0.32) (0.51) (0.29)
Current income taxes (0.50) (1.18) (0.53) (1.18)
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Funds flow netbacks 24.14 38.08 22.86 34.17
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/T/
Reflecting the impact of the Masters acquisition, depletion and depreciation expense for the second quarter of 2009 increased seven percent to $15.68 million compared to the prior quarter and the second quarter of 2008, $14.72 million and $14.69 million, respectively. On a per barrel of oil equivalent basis, the depletion and depreciation rates were $18.09, $17.75 and $17.47 for the second and first quarters of 2009 and the second quarter of 2008, respectively. The 2008 calendar year depletion and depreciation rate was $17.61 per barrel of oil equivalent.
The provision for accretion of asset retirement obligations for the first half of 2009 was $1.26 million, a 20 percent increase compared to the first half of 2008. The year-over-year increase is due to changes in the estimated future liability for asset retirement obligations as a result of wells added through Zargon's drilling program inclusive of wells acquired/disposed of in the current year and wells acquired with the recent corporate acquisitions.
The recovery of future taxes for the second quarter of 2009 was $6.11 million compared to a recovery of $3.73 million in the prior quarter and a recovery of $7.77 million in the second quarter of 2008. The 2009 second quarter increase in the future tax recovery, when compared to the 2009 first quarter recovery, is primarily related to a decrease in net earnings as a result of the increase in unrealized risk management losses in the quarter.
On October 31, 2006, the Federal Government announced tax proposals pertaining to taxation of distributions paid by trusts and the personal tax treatment of trust distributions. Currently, the Trust does not pay tax on distributions as tax is paid by the unitholders. On June 12, 2007, the Federal Government enacted these tax proposals, which would have resulted in taxation of distributions at the Trust level at a rate of 31.5 percent effective January 1, 2011. Subsequent 2007 fourth quarter legislation lowered this tax rate to 29.5 percent in 2011 and 28.0 percent beyond 2011 to assimilate recent corporate tax rate changes. Prior to June 2007, the Trust estimated the future income tax on certain temporary differences between amounts recorded on its balance sheet for book and tax purposes to have a nil effective tax rate. On February 26, 2008, the Federal Government, in its Federal Budget, announced further changes to the specified investment flow through ("SIFT") tax rules. The provincial component of the SIFT tax will be based on the provincial rates where the SIFT has a permanent establishment rather than using a 13.0 percent flat rate. During the 2009 first quarter this tax rate change had been substantively enacted, and the future income tax impact has been recorded in the financial statements. Under the legislation, the Trust now estimates the effective tax rate on the post 2010 reversal of these temporary differences to be approximately 26.5 percent for 2011 and 25.0 percent thereafter. Until 2011, Zargon's future tax obligations are reduced as distributions are made from the Trust and, consequently, it is anticipated that Zargon's effective tax rate will continue to be low until that time.
On December 15, 2006, the Canadian Federal Department of Finance stated its intention to allow conversions of SIFT income trusts to a corporation without any adverse tax consequences to investors. On July 14, 2008, the Department of Finance released the draft legislative proposals to allow the conversion of these SIFT trusts into corporations. Zargon is currently reviewing and assessing this recent legislation and is considering its potential impact on the organization while Zargon's management develops its strategic plan beyond 2010, which is the effective date of the new SIFT tax rules.
According to the January 19, 2005 CICA pronouncement, EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", Zargon Energy Trust must reflect the exchangeable securities issued by its subsidiary (Zargon Oil & Gas Ltd.) as a non-controlling interest. Prior to 2005, these exchangeable shares were reflected as a component of unitholders' equity. Accordingly, the Trust has reflected a non-controlling interest of $27.07 million on the Trust's consolidated balance sheet as at June 30, 2009. Consolidated net losses have been reduced for net losses attributable to the non-controlling interest of $0.35 million in the second quarter of 2009. In accordance with EIC-151 and given the circumstances in Zargon's case, each exchangeable share redemption is accounted for as a step-purchase, which, in the second quarter of 2009, resulted in an increase in property and equipment of $0.01 million, a decrease in unitholders' equity and non-controlling interest of $0.34 million and a nominal increase in future income tax liability. Funds flow was not impacted by this change. The cumulative impact to date of the application of EIC-151 has been to increase property and equipment by $55.24 million, unitholders' equity and non-controlling interest by $65.64 million, increase future income tax liability by $18.21 million and allocate net earnings of $28.61 million to exchangeable shareholders.
Funds flow from operating activities in the 2009 second quarter of $20.92 million was $3.07 million, or 17 percent higher than the preceding quarter and $11.10 million or 35 percent lower than the prior year second quarter. The increase in funds flow from the preceding quarter was primarily due to increased revenues (net of related royalties) as a result of higher oil prices and higher production volumes resulting from the acquisition of Masters. Compared to the prior year second quarter, a three percent increase in production volumes and an increase in realized risk management contract gains were more than offset by rising production costs, general and administrative costs and a 50 percent decrease in commodity prices. Funds flow on a per diluted trust unit basis was $0.91 for the second quarter of 2009, an eight percent increase from the prior quarter and a 41 percent decrease from the 2008 second quarter.
Net losses were $2.55 million for the 2009 second quarter compared to $0.37 million of net earnings in the preceding quarter and $4.51 million of net losses in the second quarter of 2008. The net earnings track the funds flow from operating activities for the respective periods modified by asset retirement expenditures and non-cash charges, which include depletion and depreciation, unrealized risk management gains/losses, future income taxes/recoveries and non-controlling interest. In addition to the previously noted items impacting funds flow, the primary reason for the reduced second quarter 2009 net earnings are due to $13.65 million of non-cash unrealized risk management losses in the quarter.
/T/
Capital Expenditures
Three Months Ended Six Months Ended
June 30, June 30,
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($ millions) 2009 2008 2009 2008
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Undeveloped land 1.13 2.18 2.53 4.38
Geological and geophysical
(seismic) 0.87 1.20 1.59 2.50
Drilling and completion of wells 3.77 5.29 9.99 9.50
Well equipment and facilities 2.79 2.76 7.23 4.47
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Exploration and development 8.56 11.43 21.34 20.85
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Property acquisitions (1) 0.14 2.75 0.70 5.21
Property dispositions - (0.15) - (0.17)
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Net property acquisitions (1) 0.14 2.60 0.70 5.04
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Corporate acquisitions assigned to
property and equipment (2) 40.03 12.22 40.03 59.85
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Total net capital expenditures
excluding administrative assets (1) (2) 48.73 26.25 62.07 85.74
Administrative assets 0.23 0.03 0.33 0.15
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Total net capital expenditures
(1) (2) 48.96 26.28 62.40 85.89
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(1) Amounts include capital expenditures acquired for cash and equity
issuances.
(2) Amounts include capital expenditures acquired for cash, equity
issuances, acquisition costs and net debt assumed on corporate
acquisitions.
/T/
CORPORATE ACQUISITIONS
On April 29, 2009, Zargon closed the Arrangement Agreement to acquire all the issued and outstanding common shares of Masters Energy Inc. for a total consideration of approximately 1.475 million Zargon trust units, $5.70 million in cash and the assumption of approximately $13.29 million of net debt (including adjustments and transactions costs) for a total transaction value of approximately $40.03 million. This acquisition brought 1,230 barrels of oil equivalent per day of production along with a significant Alkaline Surfactant Polymer (ASP) tertiary oil recovery opportunity at the Little Bow oil property in Southern Alberta.
The results of operations of Masters have been included in the consolidated financial statements since April 29, 2009. In relation to the second quarter 2009 results, the Masters acquisition has contributed approximately 787 barrels of oil equivalent per day of production volumes to Zargon's total quarterly production volumes of 9,520 barrels of oil equivalent per day.
On July 28, 2009, Zargon announced that it entered into an Arrangement Agreement pursuant to which Zargon has agreed to make an offer to acquire all the issued and outstanding common shares of Churchill Energy Inc. ("Churchill"). Pursuant to the Arrangement Agreement, Churchill shareholders would receive approximately 0.01363 trust units or $0.22 cash for each Churchill common share, subject to a maximum of $4.60 million cash. This corporate acquisition is valued at approximately $15.00 million and is expected to be completed in late September 2009, at which time the results of operations would be included in the consolidated financial statements. Churchill is currently producing approximately 400 barrels of oil equivalent per day.
LIQUIDITY AND CAPITAL RESOURCES
Total net capital expenditures (including net property acquisitions and consideration and net debt assumed for corporate acquisitions) of $62.40 million in the first half of 2009 were 27 percent lower than the first half of 2008 which had included the Rival Energy Ltd. and Newpact Energy Corp. acquisitions. Field expenditures of $21.34 million for the 2009 first half reflected a similar exploration and development field program when compared to $20.85 million for the 2008 first half, representing a two percent increase. Drilling and completion expenses of $9.99 million were five percent higher than the prior year's first half amount of $9.50 million. During the first half of 2009, 10.4 net wells were drilled compared to 14.3 net wells in the first half of 2008. Field capital expenditures (excluding net property acquisitions) for the first half of 2009 were allocated to Alberta Plains - $9.66 million, West Central Alberta - $5.86 million and Williston Basin - $5.82 million.
On June 5, 2009, the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of equity issuance costs). The net proceeds of the offering were used to reduce outstanding borrowings under existing credit facilities, and in turn will also be used to partially fund the 2009 capital expenditure program and for general corporate purposes.
Funds flow from operating activities in the 2009 first half of $38.77 million, proceeds from the issuance of trust units of $55.75 million (due to the acquisition of Masters, the equity issuance and unit right exercises) funded the capital program including corporate and property acquisitions, the decrease in bank debt, the changes in working capital and the cash distributions to the unitholders.
At June 30, 2009, the Trust continues to maintain a strong balance sheet with a combined debt net of working capital (excluding unrealized risk management assets and liabilities and future income taxes) of $77.47 million, compared to $91.92 million at the end of the 2009 first quarter, which represents approximately 43 percent of the Trust's available credit facilities at June 30, 2009.
The volatility of oil and natural gas prices, the changes relating to Alberta royalties and Canadian income trust tax rules and recent global economic concerns have partially restricted the oil and natural gas industry's ability to attract new capital from debt and equity markets. Zargon's historically conservative strategy of maintaining a relatively low cash distribution to funds flow ratio and conservative debt levels should enable Zargon to maintain modified capital and distribution programs during periods of limited access to debt and equity capital.
/T/
Cash Distributions Analysis
Three Months Ended Six Months Ended
June 30, June 30,
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($ millions) 2009 2008 2009 2008
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Cash flows from operating
activities 21.94 36.44 37.67 51.71
Net earnings/(losses) (2.55) (4.51) (2.19) 0.04
Actual cash distributions paid or
payable relating to the period (11.26) (9.71) (21.30) (19.26)
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Excess of cash flows from operating
activities over cash distributions
paid 10.68 26.73 16.37 32.45
Excess (shortfall) of net
earnings/(losses) over cash
distributions paid (13.81) (14.22) (23.49) (19.22)
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/T/
During the first half of 2009, Zargon has maintained a base monthly distribution of $0.18 per trust unit. Management monitors the Trust's distribution policy with respect to forecasted net cash flows, debt levels and capital expenditures. Zargon's cash distributions are discretionary to the extent that these distributions do not cause a breach of the financial covenants under Zargon's credit facilities and to the extent the Trust (non-consolidated) is not taxable. As a crude oil and natural gas Trust, Zargon's reserve base is depleted with production and Zargon, therefore, relies on ongoing exploration, development and acquisition activities to replace reserves and to offset production declines. The success of these exploration, development and acquisition capital programs, along with commodity price fluctuations and the Trust's ability to manage costs, are the main factors influencing the sustainability of the Trust's distributions.
For the three and six months ended June 30, 2009, cash flows from operating activities (after changes in non-cash working capital) of $21.94 million and $37.67 million, respectively, exceeded cash distributions of $11.26 million and $21.30 million, respectively. For the three months and six months ended June 30, 2008, cash flows from operating activities (after changes in non-cash working capital) of $36.44 million and $51.71 million, respectively, exceeded cash distributions of $9.71 million and $19.26 million, respectively.
For the three and six months ended June 30, 2009, cash distributions of $11.26 and $21.30 million, exceeded net losses of $2.55 and $2.19 million, respectively. For the three months ended June 30, 2008, net losses of $4.51 million were exceeded by cash distributions of $9.71 million. For the six months ended June 30, 2008, net earnings of $0.04 million were exceeded by cash distributions of $19.26 million. Net earnings/losses include significant non-cash charges, which were $23.88 million for the 2009 second quarter and $41.82 million for the six months ended June 30, 2009, that do not impact cash flow. Net earnings/losses also include fluctuations in future income taxes due to changes in tax rates and tax rules. In the instances where distributions exceed net earnings, a portion of the cash distribution paid to unitholders may represent an economic return of the unitholders' capital.
For the 2009 second quarter, cash distributions and net capital expenditures totalled $60.22 million ($20.19 million excluding the $40.03 million attributed to the Masters corporate acquisition), which was $38.28 million higher than the cash flows from operating activities (after changes in non-cash working capital) of $21.94 million. For the six months ended June 30, 2009, cash flows from operating activities (after changes in non-cash working capital) were exceeded by cash distributions and net capital expenditures (including the cash and non-cash portion of corporate acquisitions) by $46.03 million. For the three and six months ended June 30, 2008, cash distributions and net capital expenditures were exceeded by and exceeded cash flows from operating activities (after changes in non-cash working capital) by $0.45 and $53.44 million, respectively. Zargon relies on access to debt and capital markets to the extent cash distributions and net capital expenditures exceed cash flows from operating activities (after changes in non-cash working capital). Over the long term, Zargon expects to fund cash distributions and capital expenditures with its cash flows from operating activities; however, it will continue to fund acquisitions and growth through additional debt and equity issuances. In the crude oil and natural gas industry, because of the nature of reserve reporting, the natural reservoir declines and the risks involved in capital investment, it is not possible to distinguish between capital spent on maintaining productive capacity and capital spent on growth opportunities. Therefore, maintenance capital is not disclosed separately from development capital spending.
At August 12, 2009, Zargon Energy Trust had 22.436 million trust units and 1.849 million exchangeable shares outstanding. Assuming full conversion of exchangeable shares at the effective August 12, 2009 exchange ratio of 1.55759, there would be 25.316 million trust units outstanding. Pursuant to the trust unit rights incentive plans, there are currently an additional 1.731 million trust unit incentive rights issued and outstanding.
/T/
Capital Sources and Uses
Three Months Ended Six Months Ended
June 30, June 30,
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($ millions) 2009 2008 2009 2008
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Funds flow from operating activities 20.92 32.02 38.77 56.77
Change in bank debt (15.35) (6.74) (7.15) 28.58
Issuance of trust units 54.53 10.08 55.75 23.63
Cash distributions to unitholders (11.26) (9.71) (21.30) (19.26)
Changes in working capital and other 0.12 0.63 (3.67) (3.83)
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Total capital sources 48.96 26.28 62.40 85.89
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/T/
CHANGES IN ACCOUNTING POLICIES
As disclosed in the December 31, 2008 annual audited consolidated financial statements, on January 1, 2009, the Trust adopted the following Canadian Institute of Chartered Accountants ("CICA") Handbook Sections:
Section 3064 "Goodwill and Intangible Assets", replacing Section 3062 "Goodwill and Other Intangible Assets". Under this new guidance, fewer items meet the criteria for capitalization. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Requirements concerning goodwill are unchanged from the requirements included in the previous Section 3062, as the new Section was only amended for intangible assets. The adoption of the abstract did not significantly impact the Trust's consolidated financial statements.
Effective January 1, 2009, the Trust retrospectively adopted the recommendations of Emerging Issues Committee abstract 173 "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", which was issued in January 2009, without restatement of prior periods. The abstract requires that an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial assets and liabilities, including derivative instruments, for presentation and disclosure purposes. The adoption of the abstract did not significantly impact the Trust's consolidated financial statements.
In addition, the Trust has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined the following may have a significant impact on the Trust:
In December 2008, the CICA issued Section 1582 "Business Combinations", which will replace CICA Section 1581 of the same name. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at the date of the exchange. Currently the purchase price used is based on the market price of the shares for a reasonable period before and after the date the acquisition is agreed upon and announced. This new guidance generally requires all acquisition costs to be expensed, which currently are capitalized as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and remeasured at fair value through earnings each period until settled. Currently, only contingent liabilities that are resolved and payable are included in the cost to acquire the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from the non-current assets in the purchase price allocation. Section 1582 will be effective for the Trust on January 1, 2011, with prospective application. The Trust is currently evaluating the impact of the adoption of the new Section on its consolidated financial statements.
In December 2008, the CICA issued Sections 1601 "Consolidated Financial Statements", and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards will be effective for the Trust on January 1, 2011. The Trust is currently evaluating the impact of the adoption of these new Sections on its consolidated financial statements.
In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, the AcSB confirmed in February 2008 that International Financial Reporting Standards ("IFRS") will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. As Zargon will be required to report its results in accordance with IFRS starting in 2011, the Trust is assessing the potential impacts of this changeover and developing its plan accordingly. Zargon has enlisted an independent consulting firm to assist with the assessment and planning of this project. To date, Zargon management with the assistance of an independent consulting firm has performed an analysis of key differences between Canadian GAAP as it pertains to Zargon and IFRS. Zargon's internal steering committee is in the process of planning the steps required to achieve the proper implementation of IFRS.
The International Accounting Standards Board ("IASB") has issued amendments to IFRS 1, which addresses first time adoption of IFRS. The IASB will allow additional optional exemptions, one of which relates to full cost oil and gas accounting, resulting in a reduced administrative transition from the current Canadian full cost accounting for oil and gas activities to IFRS. The election is available at the time of adoption only. The exemption would permit the Trust to measure exploration and evaluation assets under IFRS at the carrying amount determined under Canadian GAAP at the date of transition to IFRS. In addition, the carrying amount under Canadian GAAP of production or development assets could be allocated on a pro rata basis to the underlying assets using either reserve volumes or reserve values at the date of transition. The assets to which this exemption is applied would be required to be tested for impairment at the date of transition under IFRS standards.
MANAGEMENT AND FINANCIAL REPORTING SYSTEMS
Zargon is required to comply with National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings", otherwise referred to as Canadian SOX ("C-Sox"). The 2009 certificate requires that the Trust disclose in the interim MD&A any changes in the Trust's internal controls over financial reporting that occurred during the period that have materially affected, or are reasonably likely to materially affect the Trust's internal control over financial reporting. The Trust confirms that no such changes were made to the internal controls over financial reporting during the first half of 2009.
Because of their inherent limitations, internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control systems are met.
OUTLOOK
With a strong balance sheet, 533 thousand net acres of undeveloped land, a promising internally generated project inventory and its ability to execute accretive asset and/or corporate acquisitions, Zargon continues to be well positioned to meet its value-creating objectives in 2009 and beyond. At this time in early August 2009, future commodity markets indicate that in 2009 both oil and natural gas prices will be considerably lower than their 2008 averages. Furthermore, there is evidence that some of the upward pressures on the industry's input costs have been alleviated, allowing for improved capital program efficiencies for field activities and for property and corporate acquisitions.
Although the recent world-wide economic crisis, depressed commodity prices and changes to the Canadian income trust tax rules after 2010 have negatively impacted our industry, we are optimistic about Zargon's long term value-seeking strategy. Consistent with its history, Zargon will continue to adhere to a conservative and focused strategy of exploiting its existing asset base while executing accretive acquisitions which will be funded by debt or equity issuances.
/T/
SUMMARY OF QUARTERLY RESULTS
2009
----------------------------------------------------------------------------
Q1 Q2
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Petroleum and natural gas revenue ($ millions) 31.98 35.84
Net earnings/(losses) ($ millions) 0.37 (2.55)
Net earnings/(losses) per diluted unit ($) 0.02 (0.13)
Funds flow from operating activities ($ millions) 17.85 20.92
Funds flow from operating activities per diluted
unit ($) 0.84 0.91
Cash flows from operating activities ($ millions) 15.73 21.94
Cash flows from operating activities per diluted
unit ($) 0.74 0.95
Cash distributions ($ millions) 10.03 11.26
Cash distributions declared per trust unit ($) 0.54 0.54
Net capital expenditures ($ millions) (1) 13.44 48.96
Total assets ($ millions) 440.76 466.60
Bank debt ($ millions) 85.78 70.43
Average daily production (boe) 9,213 9,520
Average realized commodity field price before the
impact of financial risk management contracts
($/boe) 38.57 41.37
Funds flow netback ($/boe) 21.53 24.14
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(1) Second quarter 2009 expenditures include corporate acquisition amounts
as follows; cash consideration of $5.70 million, transaction costs of
$0.36 million, net debt assumed of $12.93 million and the equity
issuance of trust units valued at $21.04 million.
2008
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4
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Petroleum and natural gas revenue
($ millions) 52.24 69.66 66.35 41.25
Net earnings/(losses) ($ millions) 4.56 (4.51) 40.05 28.19
Net earnings/(losses) per diluted
unit ($) 0.26 (0.25) 2.20 1.53
Funds flow from operating
activities ($ millions) 24.75 32.02 29.75 20.40
Funds flow from operating
activities per diluted unit ($) 1.23 1.55 1.42 0.97
Cash flows from operating
activities ($ millions) 15.27 36.44 33.58 24.84
Cash flows from operating
activities per diluted unit ($) 0.76 1.76 1.60 1.18
Cash distributions ($ millions) 9.55 9.71 9.87 9.96
Cash distributions declared per
trust unit ($) 0.54 0.54 0.54 0.54
Net capital expenditures
($ millions) (1) (2) (3) 59.61 26.28 17.47 16.37
Total assets ($ millions) 396.90 418.88 426.63 447.60
Bank debt ($ millions) 92.18 85.45 74.95 77.58
Average daily production (boe) 9,015 9,239 9,340 9,410
Average realized commodity field
price before the impact
of financial risk management
contracts ($/boe) 63.68 82.85 77.22 47.65
Funds flow netback ($/boe) 30.17 38.08 34.62 23.56
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) First quarter 2008 expenditures include corporate acquisition amounts
as follows; cash consideration of $16.40 million, transaction costs of
$0.29 million, net debt assumed of $17.77 million and the equity
issuance of trust units valued at $13.37 million.
(2) Second quarter 2008 net capital expenditures include corporate
acquisition amounts as follows; transaction costs of $0.15 million, net
debt assumed of $2.49 million and the equity issuance of trust units
valued at $9.39 million.
(3) Third quarter 2008 net capital expenditures include property
acquisition amounts as follows; the equity issuance of trust units
valued at $1.14 million.
2007
----------------------------------------------------------------------------
Q1 Q2 Q3 Q4
----------------------------------------------------------------------------
Petroleum and natural gas revenue
($ millions) 38.53 39.21 36.64 41.13
Net earnings ($ millions) 5.22 11.63 5.50 2.20
Net earnings per diluted unit ($) 0.31 0.68 0.32 0.13
Funds flow from operating
activities ($ millions) 21.80 20.56 17.38 20.10
Funds flow from operating
activities per diluted unit ($) 1.12 1.05 0.88 1.02
Cash flows from operating
activities ($ millions) 18.35 19.09 24.64 14.23
Cash flows from operating
activities per diluted unit ($) 0.94 0.97 1.25 0.72
Cash distributions ($ millions) 9.12 9.17 9.19 9.21
Cash distributions declared per
trust unit ($) 0.54 0.54 0.54 0.54
Net capital expenditures
($ millions) 20.93 10.97 16.43 18.35
Total assets ($ millions) 324.31 324.96 327.54 343.11
Bank debt ($ millions) 37.68 46.74 44.10 56.87
Average daily production (boe) 8,483 8,465 8,501 8,790
Average realized commodity field
price before the impact
of financial risk management
contracts ($/boe) 50.47 50.91 46.84 50.86
Funds flow netback ($/boe) 28.55 26.69 22.22 24.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ADDITIONAL INFORMATION
Additional information regarding the Trust and its business operations,
including the Trust's Annual Information Form for December 31, 2008, is
available on the Trust's SEDAR profile at www.sedar.com.
"Signed" C.H. Hansen
President and Chief Executive Officer
Calgary, Alberta
August 12, 2009
CONSOLIDATED BALANCE SHEETS
(unaudited)
----------------------------------------------------------------------------
June 30, December 31,
($ thousands) 2009 2008
----------------------------------------------------------------------------
ASSETS (note 5)
Current
Accounts receivable 21,595 20,725
Prepaid expenses and deposits 1,513 1,162
Unrealized risk management asset (note 11) 15,545 29,641
Future income taxes 301 -
----------------------------------------------------------------------------
38,954 51,528
Long term deposit 1,882 1,612
Unrealized risk management asset (note 11) 65 4,745
Goodwill 2,969 2,969
Property and equipment, net (notes 3 and 4) 422,726 386,746
----------------------------------------------------------------------------
466,596 447,600
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current
Accounts payable and accrued liabilities 26,108 28,687
Cash distributions payable (note 15) 4,038 3,326
Unrealized risk management liability (note 11) 1,019 724
Future income taxes 4,598 8,553
----------------------------------------------------------------------------
35,763 41,290
Long term debt (note 5) 70,431 77,581
Unrealized risk management liability (note 11) 1,036 281
Asset retirement obligations (note 6) 32,881 28,592
Future income taxes 43,852 49,704
----------------------------------------------------------------------------
183,963 197,448
----------------------------------------------------------------------------
NON-CONTROLLING INTEREST
Exchangeable shares (note 8) 27,068 27,610
----------------------------------------------------------------------------
UNITHOLDERS' EQUITY
Unitholders' capital (note 7) 177,102 120,650
Contributed surplus (note 7) 4,670 4,617
Accumulated earnings 254,918 257,104
Accumulated cash distributions (181,125) (159,829)
----------------------------------------------------------------------------
255,565 222,542
----------------------------------------------------------------------------
466,596 447,600
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF EARNINGS AND
COMPREHENSIVE INCOME AND ACCUMULATED EARNINGS
Three Months Ended Six Months Ended
(unaudited) June 30, June 30,
----------------------------------------------------------------------------
($ thousands, except per unit amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
REVENUE
Petroleum and natural gas revenue 35,838 69,656 67,818 121,895
Unrealized risk management loss
(note 11) (13,654) (29,632) (19,825) (36,492)
Realized risk management
gain/(loss) (note 11) 7,449 (8,947) 15,078 (11,814)
Royalties (5,994) (14,040) (11,580) (24,751)
----------------------------------------------------------------------------
23,639 17,037 51,491 48,838
----------------------------------------------------------------------------
EXPENSES
Production 11,333 9,433 22,578 18,594
General and administrative 3,714 2,609 7,090 4,842
Unit-based compensation (note 7) 282 262 425 517
Interest and financing charges 491 1,356 1,111 2,689
Unrealized foreign exchange gain/(loss) 53 139 49 (11)
Accretion of asset retirement
obligations (note 6) 670 542 1,262 1,049
Depletion and depreciation 15,675 14,686 30,393 28,915
----------------------------------------------------------------------------
32,218 29,027 62,908 56,595
----------------------------------------------------------------------------
EARNINGS/(LOSSES) BEFORE INCOME TAXES (8,579) (11,990) (11,417) (7,757)
----------------------------------------------------------------------------
INCOME TAXES
Current 430 990 899 1,951
Future tax recovery (6,110) (7,773) (9,837) (9,757)
----------------------------------------------------------------------------
(5,680) (6,783) (8,938) (7,806)
----------------------------------------------------------------------------
EARNINGS/(LOSSES) FOR THE PERIOD
BEFORE NON CONTROLLING INTEREST (2,899) (5,207) (2,479) 49
Non-controlling interest
- exchangeable shares (note 8) 346 695 293 (5)
----------------------------------------------------------------------------
NET EARNINGS/(LOSSES) AND COMPREHENSIVE
INCOME /(LOSSES) FOR THE PERIOD (2,553) (4,512) (2,186) 44
ACCUMULATED EARNINGS, BEGINNING OF
PERIOD 257,471 193,375 257,104 188,819
----------------------------------------------------------------------------
ACCUMULATED EARNINGS, END OF PERIOD 254,918 188,863 254,918 188,863
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NET EARNINGS/(LOSSES) PER UNIT (note 9)
Basic (0.13) (0.25) (0.11) -
Diluted (0.13) (0.25) (0.11) -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended Six Months Ended
(unaudited) June 30, June 30,
----------------------------------------------------------------------------
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings/(losses) for the
period (2,553) (4,512) (2,186) 44
Add (deduct) non-cash items:
Non-controlling interest
- exchangeable shares (346) (695) (293) 5
Unrealized risk management loss 13,654 29,632 19,825 36,492
Depletion and depreciation 15,675 14,686 30,393 28,915
Accretion of asset retirement
obligations 670 542 1,262 1,049
Unit-based compensation 282 262 425 517
Unrealized foreign exchange
(gain)/loss 53 139 49 (11)
Future income tax recovery (6,110) (7,773) (9,837) (9,757)
Asset retirement expenditures (406) (266) (871) (489)
----------------------------------------------------------------------------
20,919 32,015 38,767 56,765
Changes in non-cash operating
working capital (note 12) 1,019 4,423 (1,100) (5,053)
----------------------------------------------------------------------------
21,938 36,438 37,667 51,712
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Advances/(repayment) of bank debt (15,347) (6,736) (7,150) 11,666
Cash distributions to unitholders (11,264) (9,713) (21,296) (19,258)
Exercise of unit rights 44 693 1,269 877
Issuance of unitholders capital,
net of issue costs 33,444 - 33,444 -
Changes in non-cash financing
working capital (note 12) 692 83 712 192
----------------------------------------------------------------------------
7,569 (15,673) 6,979 (6,523)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Additions to property and equipment (8,936) (14,215) (22,379) (26,210)
Proceeds on disposal of property
and equipment 6 150 6 170
Corporate acquisitions (cash
portion) (18,882) (148) (18,882) (16,835)
Long term deposit (270) (76) (270) (157)
Changes in non-cash investing
working capital (note 12) (1,425) (6,476) (3,121) (2,157)
----------------------------------------------------------------------------
(29,507) (20,765) (44,646) (45,189)
----------------------------------------------------------------------------
NET CHANGE IN CASH DURING THE
PERIOD AND CASH, END OF PERIOD - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes.
/T/
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the three and six months ended June 30, 2009 and 2008 (unaudited).
1. BASIS OF PRESENTATION
The interim unaudited consolidated financial statements of Zargon Energy Trust (the "Trust" or "Zargon") have been prepared by management in accordance with Canadian generally accepted accounting principles. The interim unaudited consolidated financial statements have been prepared following the same accounting policies and methods in computation as the consolidated financial statements for the fiscal year ended December 31, 2008, except as noted below. The disclosures provided below are incremental to those included with the annual audited consolidated financial statements. These interim unaudited consolidated financial statements do not include all disclosures required in the annual consolidated financial statements and should be read in conjunction with the consolidated financial statements and notes thereto in the Zargon Energy Trust annual financial report for the year ended December 31, 2008.
The Trust's principal business activity is the exploration for and development and production of petroleum and natural gas in Canada and the United States ("US").
2. CHANGES IN ACCOUNTING POLICIES
As disclosed in the December 31, 2008 annual audited consolidated financial statements, on January 1, 2009, the Trust adopted the following Canadian Institute of Chartered Accountants ("CICA") Handbook Sections:
Section 3064 "Goodwill and Intangible Assets", replacing Section 3062 "Goodwill and Other Intangible Assets". Under this new guidance, fewer items meet the criteria for capitalization. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. Requirements concerning goodwill are unchanged from the requirements included in the previous Section 3062, as the new Section was only amended for intangible assets. The adoption of the abstract did not significantly impact the Trust's consolidated financial statements.
Effective January 1, 2009, the Trust retrospectively adopted the recommendations of Emerging Issues Committee abstract 173 "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", which was issued in January 2009, without restatement of prior periods. The abstract requires that an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial assets and liabilities, including derivative instruments, for presentation and disclosure purposes. The adoption of the abstract did not significantly impact the Trust's consolidated financial statements.
In addition, the Trust has assessed new and revised accounting pronouncements that have been issued that are not yet effective and determined the following may have a significant impact on the Trust:
In December 2008, the CICA issued Section 1582 "Business Combinations", which will replace CICA Section 1581 of the same name. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at the date of the exchange. Currently the purchase price used is based on the market price of the shares for a reasonable period before and after the date the acquisition is agreed upon and announced. This new guidance generally requires all acquisition costs to be expensed, which currently are capitalized as part of the purchase price. Contingent liabilities are to be recognized at fair value at the acquisition date and remeasured at fair value through earnings each period until settled. Currently, only contingent liabilities that are resolved and payable are included in the cost to acquire the business. In addition, negative goodwill is required to be recognized immediately in earnings, unlike the current requirement to eliminate it by deducting it from the non-current assets in the purchase price allocation. Section 1582 will be effective for the Trust on January 1, 2011, with prospective application. The Trust is currently evaluating the impact of the adoption of the new Section on its consolidated financial statements.
In December 2008, the CICA issued Sections 1601 "Consolidated Financial Statements", and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. These standards will be effective for the Trust on January 1, 2011. The Trust is currently evaluating the impact of the adoption of these new Sections on its consolidated financial statements.
In January 2006, the CICA Accounting Standards Board ("AcSB") adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, the AcSB confirmed in February 2008 that International Financial Reporting Standards ("IFRS") will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. The Trust is currently reviewing the standards to determine the potential impact on its consolidated financial statements. The Trust, with the assistance of an independent consulting firm, has performed a diagnostic analysis that identifies differences between the Trust's current accounting policies and IFRS. At this time, the Trust is evaluating the impact of these differences and assessing the need for amendments to existing accounting policies in order to comply with IFRS.
The International Accounting Standards Board ("IASB") has issued amendments to IFRS 1, which addresses first time adoption of IFRS. The IASB will allow additional optional exemptions, one of which relates to full cost oil and gas accounting, resulting in a reduced administrative transition from the current Canadian full cost accounting for oil and gas activities to IFRS. The election is available at the time of adoption only. The exemption would permit the Trust to measure exploration and evaluation assets under IFRS at the carrying amount determined under Canadian GAAP at the date of transition to IFRS. In addition, the carrying amount under Canadian GAAP of production or development assets could be allocated on a pro rata basis to the underlying assets using either reserve volumes or reserve values at the date of transition. The assets to which this exemption is applied would be required to be tested for impairment at the date of transition under IFRS standards.
3. ACQUISITIONS
Masters Energy Inc.
On April 29, 2009, a subsidiary of the Trust acquired all of the outstanding shares of Masters Energy Inc. ("Masters"), a public oil and gas company, for consideration of $27.10 million. Consideration consisted of $5.70 million cash, the issuance of 1,475,468 Zargon trust units valued at $14.26 per unit and acquisition costs of $0.36 million. Zargon assumed Masters' long term debt, which was repaid on the closing date of the acquisition.
The results of operations for Masters have been included in the consolidated financial statements since April 29, 2009.
The acquisition was accounted for by the purchase method and the preliminary purchase price allocation is as follows:
/T/
Net Assets Acquired
($ thousands)
----------------------------------------------------------------------------
Property and equipment 43,698
Working capital deficiency (105)
Long term debt (12,825)
Future income tax asset 69
Asset retirement obligations (3,740)
----------------------------------------------------------------------------
Total net assets acquired 27,097
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration
($ thousands)
----------------------------------------------------------------------------
Cash 5,700
Trust units issued 21,040
Acquisition costs 357
----------------------------------------------------------------------------
Total purchase price 27,097
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Rival Energy Ltd.
On January 23, 2008, a subsidiary of the Trust acquired all of the outstanding shares of Rival Energy Ltd. ("Rival"), a public oil and gas company, for consideration of $30.06 million. Consideration consisted of $16.40 million cash, the issuance of 573,300 Zargon trust units valued at $23.32 per unit and acquisition costs of $0.29 million.
The results of operations for Rival have been included in the consolidated financial statements since January 23, 2008.
The acquisition was accounted for by the purchase method and the purchase price allocation is as follows:
/T/
Net Assets Acquired
($ thousands)
----------------------------------------------------------------------------
Property and equipment 54,065
Goodwill 2,969
Working capital deficiency (854)
Long term debt (16,914)
Future income tax liability (5,443)
Asset retirement obligations (3,767)
----------------------------------------------------------------------------
Total net assets acquired 30,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration
($ thousands)
----------------------------------------------------------------------------
Cash 16,400
Trust units issued 13,369
Acquisition costs 287
----------------------------------------------------------------------------
Total purchase price 30,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Newpact Energy Corp.
On May 16, 2008, a subsidiary of the Trust acquired all of the outstanding shares of Newpact Energy Corp. ("Newpact"), a private oil and gas company, for consideration of $9.54 million. Consideration consisted of the issuance of 425,940 Zargon trust units valued at $22.04 per unit and acquisition costs of $0.15 million.
The results of operations for Newpact have been included in the consolidated financial statements since May 16, 2008.
The acquisition was accounted for by the purchase method and the purchase price allocation is as follows:
/T/
Net Assets Acquired
($ thousands)
----------------------------------------------------------------------------
Property and equipment 13,925
Working capital deficiency (2,491)
Future income tax liability (922)
Asset retirement obligations (976)
----------------------------------------------------------------------------
Total net assets acquired 9,536
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration
($ thousands)
----------------------------------------------------------------------------
Trust units issued 9,388
Acquisition costs 148
----------------------------------------------------------------------------
Total purchase price 9,536
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. PROPERTY AND EQUIPMENT
June 30, 2009
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousands) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas properties
and other equipment (1) 737,697 314,971 422,726
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, 2008
----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
($ thousands) Cost Depreciation Value
----------------------------------------------------------------------------
Petroleum, natural gas Properties
and other equipment (1) 671,324 284,578 386,746
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) As a result of shareholders redeeming exchangeable shares, property and
equipment has cumulatively increased $55.24 million, $0.09 million
relating to the first six months of 2009, $3.39 million relating to 2008
and $51.76 million relating to prior years. The effect of these
increases has resulted in additional depletion and depreciation expense
of approximately $24.78 million, $2.47 million relating to the first six
months of 2009, $5.59 million relating to 2008, and $16.72 million
relating to prior years.
/T/
5. LONG TERM DEBT
On July 27, 2009, Zargon amended and renewed its syndicated committed credit facilities, the result of which was the maintaining of the available facilities and borrowing base of $180 million. These facilities consist of a $170 million tranche available to the Canadian borrower and a US $8 million tranche available to the US borrower. A $300 million demand debenture on the assets of the subsidiaries of the Trust has been provided as security for these facilities. The facilities are fully revolving for a 336 day period with the provision for an annual extension at the option of the lenders and upon notice from Zargon's management. The next renewal date is June 29, 2010. Should the facilities not be renewed, they convert to one year non-revolving term facilities at the end of the revolving 336 day period. Repayment would not be required until the end of the non-revolving term, and, as such, these facilities have been classified as long term debt.
Interest rates fluctuate under the syndicated facilities with Canadian prime, US prime and US base rates plus an applicable margin between 125 basis points and 275 basis points (2008 - zero and 32.5 basis points, respectively), as well as with Canadian banker's acceptance and LIBOR rates plus an applicable margin between 275 basis points and 425 basis points (2008 - 97.5 and 157.5 basis points, respectively). At June 30, 2009, $70.43 million (December 31, 2008 - $77.58 million) had been drawn on the syndicated committed credit facilities with any unused amounts subject to standby fees. In the normal course of operations Zargon enters into various letters of credit. At June 30, 2009, the approximate value of outstanding letters of credit totalled $0.50 million (December 31, 2008 - $0.52 million).
6. ASSET RETIREMENT OBLIGATIONS
The following table reconciles Zargon's asset retirement obligations:
/T/
Six Months Ended June 30,
----------------------------------------------------------------------------
($ thousands) 2009 2008
----------------------------------------------------------------------------
Balance, beginning of period 28,592 21,184
Net liabilities incurred/acquired 3,955 5,455
Liabilities settled (871) (489)
Accretion expense 1,262 1,049
Foreign exchange (57) 25
----------------------------------------------------------------------------
Balance, end of period 32,881 27,224
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. UNITHOLDERS' EQUITY
The Trust is authorized to issue an unlimited number of voting trust units.
Trust Units
Six Months Ended June 30, 2009
----------------------------------------------------------------------------
Number
(thousands) of units Amount ($)
----------------------------------------------------------------------------
Balance, beginning of period 18,479 120,650
Unit rights exercised for cash 96 1,269
Unit-based compensation recognized on exercise of
unit rights - 387
Issued on corporate acquisition 1,476 21,040
Equity issuance (net of share issue costs) 2,365 33,444
Issued on conversion of exchangeable shares 20 312
----------------------------------------------------------------------------
Balance, end of period 22,436 177,102
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
The proforma total units outstanding at June 30, 2009, including trust units outstanding and trust units issuable upon conversion of exchangeable shares, after giving effect to the exchange ratio at the end of the period (see note 8) is 25.283 million units.
On June 5, 2009, the Trust closed an offering of 2.365 million trust units on a bought deal basis at $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of issue costs).
The following table summarizes information about the Trust's contributed surplus account:
/T/
Contributed Surplus
($ thousands) Six Months Ended June 30, 2009
----------------------------------------------------------------------------
Balance, beginning of period 4,617
Unit-based compensation expense (1) 440
Unit-based compensation recognized on exercise of unit rights (387)
----------------------------------------------------------------------------
Balance, end of period 4,670
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) During the fourth quarter of 2008, the Trust issued 10,000 unit
appreciation rights ("UARS"). The intrinsic value at June 30, 2009 has
decreased by 0.02 million since December 31, 2008 ($0.04 million). These
UARS are awards entitling the recipients to receive cash in an amount
equivalent to any excess of the market value of a stated number of units
over a stated price. UARS are included in unit-based compensation
expense; however rewards settled in cash are liabilities and therefore
are not included in contributed surplus.
/T/
Trust Unit Rights Incentive Plans and Unit-Based Compensation
The Trust has a unit rights incentive plan (the "Old Plan") that allows the Trust to issue rights to acquire trust units to directors, officers, employees and other service providers. On April 22, 2009, a new unit rights incentive plan (the "New Plan") was approved. The Trust is authorized to issue up to an aggregate of 2.13 million unit rights; however, the number of trust units reserved for issuance upon exercise of the rights shall not at any time exceed 10 percent of the aggregate number of the total outstanding units, including units issuable upon exchange of exchangeable shares of Zargon and other fully paid securities of Zargon entities exchangeable into units, which are the economic equivalent of units including full voting rights. At the time of grant, unit right exercise prices approximate the market price for the trust units. At the time of exercise, the rights holder has the option of exercising at the original grant price or the exercise price as calculated under the Old Plan or the New Plan (the "modified price"). Under the Old Plan, the modified price was based on the increment of the amount the monthly distribution exceeded a monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the Old Plan). Under the New Plan, if the monthly distribution exceeds the monthly return of 0.833 percent of the Trust's recorded net book value of oil and natural gas properties (as defined in the New Plan), the entire amount (not the increment) of the distribution is deducted from the original grant price. Rights granted under either Plan generally vest over a three-year period and expire approximately five years from the grant date. Zargon uses a fair value methodology to value the unit rights grants.
The weighted average assumptions made for unit rights granted for the three and six months ended June 30, 2009 include a volatility factor of expected market price of 34.5 percent, a risk-free interest rate of 1.6 percent and an expected life of the unit rights of four years. The fair value of the unit rights granted in the quarter was calculated at $4.43 per unit right. Unit-based compensation expense for the three and six months ended June 30, 2009 of $0.28 million (2008 - $0.26 million) and $0.44 million (2008 - $0.52 million), respectively.
Compensation expense associated with unit rights granted under either Plan is recognized in earnings over the vesting period of the Plan with a corresponding increase in contributed surplus. The exercise of trust unit rights is recorded as an increase in trust units with a corresponding reduction in contributed surplus. Forfeiture of rights are recorded as a reduction in expenses in the period in which they occur.
The following table summarizes information about the Trust's unit rights under the Old Plan:
/T/
Six Months Ended June 30, 2009
----------------------------------------------------------------------------
Weighted Average
Number of Exercise Price
Unit Rights Initial and Modified
(thousands) ($/unit right)
----------------------------------------------------------------------------
Outstanding at beginning of period 1,654 25.57 / 23.63
Unit rights granted - -
Unit rights exercised (96) 13.20
Unit rights forfeited (137) 26.22
-------------------------------------------------------
Outstanding at end of period 1,421 26.04 / 24.13
-------------------------------------------------------
Unit rights exercisable at period end 1,053 26.90 / 24.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes information about the Trust's unit rights
under the New Plan:
Six Months Ended June 30, 2009
----------------------------------------------------------------------------
Weighted Average
Number of Exercise Price
Unit Rights Initial and Modified
(thousands) ($/unit right)
----------------------------------------------------------------------------
Outstanding at beginning of period - -
Unit rights granted 380 15.56 / 15.32
Unit rights exercised - -
Unit rights forfeited - -
-------------------------------------------------------
Outstanding at end of period 380 15.56 / 15.32
-------------------------------------------------------
Unit rights exercisable at period end - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
8. NON-CONTROLLING INTEREST - EXCHANGEABLE SHARES
Zargon Oil & Gas Ltd. is authorized to issue an unlimited number of exchangeable shares. The exchangeable shares are convertible into trust units at the option of the shareholder, based on the exchange ratio, which is adjusted monthly to reflect the distribution paid on the trust units. Cash distributions are not paid on the exchangeable shares. During the six months ended June 30, 2009, a total of 0.01 million (2008 - 0.02 million) exchangeable shares were converted into 0.02 million (2008 - 0.02 million) trust units based on the exchange ratio at the time of conversion. At June 30, 2009, the exchange ratio was 1.53987 trust units per exchangeable share.
/T/
Non-Controlling Interest - Exchangeable Shares
Six Months Ended June 30, 2009
----------------------------------------------------------------------------
(thousands, except exchange ratio) Number of Shares Amount ($)
----------------------------------------------------------------------------
Balance, beginning of period 1,862 27,610
Exchanged for trust units at book value and
including earnings attributed during the period (13) (249)
Earnings attributable to non-controlling interest - (293)
----------------------------------------------------------------------------
Balance, end of period 1,849 27,068
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exchange ratio, end of period 1.53987
Trust units issuable upon conversion of
exchangeable shares, end of period 2,847
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Per EIC-151 "Exchangeable Securities Issued by Subsidiaries of Income Trusts", if certain conditions are met, the exchangeable shares issued by a subsidiary must be reflected as non-controlling interest on the consolidated balance sheets and, in turn, net earnings must be reduced by the amount of net earnings attributed to the non-controlling interest.
The non-controlling interest on the consolidated balance sheets consists of the book value of exchangeable shares at the time of the Plan of Arrangement, plus net earnings attributable to the exchangeable shareholders, less exchangeable shares (and related cumulative earnings) redeemed. The net earnings attributable to the non-controlling interest on the consolidated statements of earnings and comprehensive income represents the cumulative share of net earnings attributable to the non-controlling interest based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable each period end.
The effect of EIC-151 on Zargon's unitholders' capital and exchangeable shares is as follows:
/T/
Zargon Zargon Oil
Energy & Gas Ltd.
Trust Exchangeable
($ thousands) Units Shares Total
----------------------------------------------------------------------------
Balance at January 1, 2009 120,650 27,610 148,260
Issued on redemption of exchangeable
shares at book value 33 (33) -
Effect of EIC-151 279 (509) (230)
Unit-based compensation recognized on
exercise of unit rights 387 - 387
Issued on corporate acquisitions 21,040 - 21,040
Unit rights exercised for cash 1,269 - 1,269
Equity issuance (net of share issue
costs) 33,444 - 33,444
----------------------------------------------------------------------------
Balance at June 30, 2009 177,102 27,068 204,170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
9. WEIGHTED AVERAGE NUMBER OF TOTAL UNITS
Basic per unit amounts are calculated using the weighted average number of trust units outstanding during the period. Diluted per unit amounts are calculated using the treasury stock method to determine the dilutive effect of unit-based compensation. Diluted per unit amounts also include exchangeable shares using the "if-converted" method. Due to the fact that at the time of exercise, the rights holder has the option of exercising at the original grant price or a modified price as calculated under the Plans, the prices used in the treasury stock calculation are the lower prices calculated under the Plans.
/T/
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
(thousands of units) 2009 2008 2009 2008
----------------------------------------------------------------------------
Basic 20,249 17,906 19,409 17,714
Diluted 23,001 20,706 22,069 20,422
----------------------------------------------------------------------------
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/T/
10. CAPITAL DISCLOSURES
The Trust's capital structure is comprised of unitholders' equity plus long term debt. The Trust's objectives when managing its capital structure are to:
i) maintain financial flexibility so as to preserve Zargon's access to capital markets and its ability to meet its financial obligations; and
ii) finance internally generated growth as well as acquisitions.
The Trust monitors its capital structure and short term financing requirements using the non-GAAP financial metric of debt net of working capital ("net debt") to funds flow from operating activities. Net debt, as used by the Trust, is calculated as bank debt and any working capital deficit excluding the current portion of unrealized risk management assets and liabilities and future income taxes. Funds flow from operating activities represents net earnings/losses and asset retirement expenditures except for non-cash items. The metric is used to steward the Trust's overall debt position as a measure of the Trust's overall financial strength and is calculated as follows:
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($ thousands, except ratio) June 30, 2009 December 31, 2008
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Net debt 77,469 87,707
Annualized funds flow from operating
activities (1) 77,534 106,909
Net debt to funds flow from operating
activities ratio 1.0 0.8
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(1) Annualized funds flow from operating activities based on six months for
2009.
/T/
Zargon's net debt to funds flow from operating activities ratio was 1.0, an increase from 0.8 at December 31, 2008, primarily due to weak commodity prices negatively affecting funds flow from operating activities. Bank debt levels decreased in the current quarter when the Trust closed on offering of 2.365 million trust units on a bought deal basis of $15.00 per unit for total gross proceeds of $35.48 million ($33.44 million net of issue costs). On July 27, 2009, Zargon amended and renewed its syndicated committed credit facilities of $180 million. The next renewal date is June 29, 2010. These facilities continue to be available for general corporate purposes and the potential acquisition of oil and natural gas properties.
To manage its capital structure, the Trust may adjust capital spending, adjust distributions paid to unitholders, issue new units, issue new debt or repay existing debt.
The Trust's capital management objectives, evaluation measures, definitions and targets have remained unchanged over the periods presented. Zargon is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants.
11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT CONTRACTS
All financial instruments are required to be measured at fair value on initial recognition of the instrument, except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as "held-for-trading", "available-for-sale", "held-to-maturity", "loans and receivables", or "other financial liabilities" as defined by CICA Section 3855.
Financial assets and financial liabilities classified as "held-for-trading" are measured at fair value with changes in fair value recognized in earnings. Financial assets classified as "available-for-sale" are measured at fair value, with changes in fair value recognized in other comprehensive income ("OCI") until the asset is removed from the consolidated balance sheets. Financial assets classified as "held-to-maturity", "loans and receivables" and "other financial liabilities" are measured at amortized cost using the effective interest method of amortization.
Fair Value of Financial Assets and Liabilities
Zargon's financial assets and liabilities are comprised of accounts receivable, deposits, accounts payable, cash distributions payable, unrealized risk management assets and liabilities and long term debt. Fair values of financial assets and liabilities, summarized information related to risk management positions and discussion of risks associated with financial assets and liabilities are presented as follows:
A) Fair Value of Financial Assets and Liabilities
Accounts receivable are designated as "loans and receivables". Accounts payable and accrued liabilities, cash distributions payable and long term debt are designated as "other liabilities". The fair values of these accounts approximate their carrying amounts.
Risk management assets and liabilities are derivative financial instruments classified as "held-for-trading". These accounts are recorded at their estimated fair value using quoted market prices.
B) Risk Management Assets and Liabilities
The Trust is a party to certain financial instruments that have fixed the price of a portion of its oil and natural gas production and foreign exchange conversion rates. The Trust enters into these contracts for risk management purposes only, in order to protect a portion of its future cash flow from the volatility of oil and natural gas commodity prices and foreign exchange rates. For financial risk management contracts, the Trust considers these contracts to be effective on an economic basis but has decided not to designate these contracts as hedges for accounting purposes and, accordingly, any unrealized gains or losses are recorded in earnings based on the fair value (mark-to-market) of the contracts at year end. The unrealized loss for the first half of 2009 was $19.83 million and the unrealized loss for the first half of 2008 was $36.49 million.
As at June 30, 2009, the Trust had the following outstanding commodity and foreign currency risk management contracts:
Commodity Financial Risk Management Contracts:
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Fair Market
Value
Weighted Gain/(Loss)
Rate Average Price Range of Terms ($ thousands)
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Oil swaps 300 bbl/d $107.40 US/bbl Jul. 1/09 - Sep. 30/09 1,167
1,000 bbl/d $100.14 US/bbl Jul. 1/09 - Dec. 31/09 6,036
200 bbl/d $75.25 US/bbl Jul. 1/09 - Dec. 31/10 134
300 bbl/d $132.98 US/bbl Oct. 1/09 - Jun. 30/10 5,627
800 bbl/d $69.40 US/bbl Jan. 1/10 - Dec. 31/10 (2,016)
Natural
gas swaps 2,000 gj/d $9.60/gj Jul. 1/09 - Oct. 31/09 1,528
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Total Fair Market Value, Commodity Price Financial Contracts 12,476
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Oil swaps are settled against the NYMEX WTI pricing index, whereas natural
gas swaps are settled against the AECO pricing index.
Foreign Exchange Financial Risk Management Contracts:
Average Foreign
Monthly US Exchange Fair Market
Dollar Rate Value Gain
Volume ($Cdn/$US) Range of Terms ($ thousands)
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Foreign exchange
forwards $1,606,000 1.1760 Jul. 1/09 - Dec. 31/09 131
$1,285,000 1.2550 Jul. 1/09 - Dec. 31/09 871
$1,203,000 1.1715 Jan. 1/10 - Jun. 30/10 77
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Total Fair Market Value, Foreign Exchange Financial Contracts 1,079
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The contracts are settled based on the average daily noon close rate for US
dollars converted to Canadian dollars as published by the Bank of Canada.
Physical Risk Management Contracts:
Fair Market
Weighted Value Gain
Rate Average Range of Terms ($ thousands)
Price
----------------------------------------------------------------------------
Natural gas fixed
price 3,000 gj/d $8.47/gj Jul. 1/09 - Oct. 31/09 1,875
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Total Fair Market Value, Physical Contracts 1,875
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/T/
Contracts settled by way of physical delivery are recognized as part of the normal revenue stream. These instruments have no book values recorded in the consolidated financial statements.
Commodity Price Sensitivities
The following table summarizes the sensitivity of the fair value of the Trust's risk management positions to fluctuations in commodity prices, with all other variables held constant. When assessing the potential impact of these commodity price changes, the Trust believes 10 percent volatility is a reasonable long term measure.
Fluctuations of 10% in commodity prices could have resulted in unrealized gains/(losses) on risk management contracts impacting net earnings as follows:
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Three and Six Months Ended June 30,
----------------------------------------------------------------------------
($ thousands) 2009 2008
----------------------------------------------------------------------------
Natural gas price 83 2,145
Crude oil price 5,974 12,057
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/T/
C) Risks Associated with Financial Assets and Liabilities
The Trust is exposed to financial risks arising from its financial assets and liabilities. The financial risks include market risk (commodity prices, interest rates and foreign exchange rates), credit risk and liquidity risk.
- Market Risk
Market risk is the risk that the fair value or future cash flows of financial assets or liabilities will fluctuate due to movements in market prices and is comprised of the following:
- Commodity Price Risk
As a means of mitigating exposure to commodity price risk volatility, the Trust has entered into various derivative agreements. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Trust's policy is to not use derivative financial instruments for speculative purposes.
Natural Gas - To partially mitigate the natural gas commodity price risk, the Trust enters into swaps, which fix the Canadian dollar AECO prices.
Crude Oil - The Trust has partially mitigated its exposure to the WTI NYMEX price with fixed price swaps.
- Interest Rate Risk
Borrowings under bank credit facilities are market rate based (variable interest rates); thus, carrying values approximate fair values.
At the June 30, 2009 debt pricing levels, the increase or decrease in net earnings for each one percent change in interest rates would amount to $0.44 million (2008 - $0.45 million).
- Foreign Exchange Risk
As Zargon operates in North America, fluctuations in the exchange rate between the US/Canadian dollar can have a significant effect on the Trust's reported results. A $0.01 change in the US to Canadian dollar exchange rate would have resulted in a $0.28 million (2008 - $0.58 million) increase or decrease in net earnings at June 30, 2009. In order to mitigate the Trust's exposure to foreign exchange fluctuations, the Trust enters into foreign exchange derivative agreements.
- Credit Risk
Credit risk is the risk that the counterparty to a financial asset will default, resulting in the Trust incurring a financial loss. This credit exposure is mitigated with credit practices that limit transactions according to counterparties' credit quality. A substantial portion of the Trust's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks.
The maximum credit risk exposure associated with accounts receivable, accrued revenues and risk management assets is the total carrying value. The Trust monitors these balances monthly to limit the risk associated with collection. Of Zargon's accounts receivable at June 30, 2009, approximately 35 percent was owing from two companies and Zargon anticipates full collection. As at December 31, 2008, approximately 37 percent was owing.
- Liquidity Risk
Liquidity risk is the risk the Trust will encounter difficulties in meeting its financial liability obligations. The Trust manages its liquidity risk through cash and debt management. See note 10 for a more detailed discussion.
As at June 30, 2009, Zargon had available unused committed bank credit facilities of approximately $109.07 million compared to $101.90 at December 31, 2008. The Trust believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.
The timing of cash outflows relating to financial liabilities are outlined in the table below:
/T/
($ thousands) 1 year 2-3 years Total
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Accounts payable and accrued liabilities 26,108 - 26,108
Cash distributions payable 4,038 - 4,038
Risk management liabilities (1) 1,019 1,036 2,055
Long term debt - 70,431 70,431
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(1) See the section titled "Commodity Price Sensitivities" in this note for
a better understanding of the volatility around these amounts.
12. CHANGES IN NON-CASH WORKING CAPITAL
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Changes in non-cash working capital
items:
Accounts receivable (1,439) (7,005) (870) (11,019)
Prepaid expenses and deposits (268) (111) (351) 254
Accounts payable and accrued
liabilities 1,909 7,928 (2,579) 6,749
Cash distributions payable 692 83 712 192
Working capital acquired from corporate
acquisitions (105) (2,684) (105) (3,345)
Foreign exchange and other (503) (181) (316) 151
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286 (1,970) (3,509) (7,018)
----------------------------------------------------------------------------
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Changes relating to operating
activities 1,019 4,423 (1,100) (5,053)
Changes relating to financing
activities 692 83 712 192
Changes relating to investing
activities (1,425) (6,476) (3,121) (2,157)
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286 (1,970) (3,509) (7,018)
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13. SUPPLEMENTAL CASH FLOW INFORMATION
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash interest paid 505 1,093 1,331 1,776
Cash taxes paid (128) 1,746 (63) 1,805
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14. SEGMENTED INFORMATION
Zargon's entire operating activities are related to exploration, development
and production of oil and natural gas in the geographic segments of Canada
and the US.
Three Months Ended Six Months Ended
June 30, June 30,
----------------------------------------------------------------------------
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Petroleum and Natural Gas Revenue
Canada 31,875 61,176 61,210 106,690
United States 3,963 8,480 6,608 15,205
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Total 35,838 69,656 67,818 121,895
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Net Capital Expenditures (1)
Canada 48,879 26,185 62,321 85,385
United States 78 101 79 507
----------------------------------------------------------------------------
Total 48,957 26,286 62,400 85,892
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(1) For net capital expenditures, amounts include capital expenditures
acquired for cash, equity issuances, acquisition costs and net debt
assumed on corporate acquisitions.
June 30, December 31,
($ thousands) 2009 2008
----------------------------------------------------------------------------
Property and Equipment, net
Canada 390,480 353,174
United States 32,246 33,572
----------------------------------------------------------------------------
Total 422,726 386,746
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Goodwill
Canada 2,969 2,969
United States - -
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Total 2,969 2,969
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15. CASH DISTRIBUTIONS
During the six month period, the Trust declared distributions to the
unitholders in the aggregate amount of $21.30 million (2008 - $19.26
million) in accordance with the following schedule:
2009 Distributions Record Date Distribution Date Per Trust Unit
----------------------------------------------------------------------------
January January 31, 2009 February 16, 2009 $0.18
February February 28, 2009 March 16, 2009 $0.18
March March 31, 2009 April 15, 2009 $0.18
April April 30, 2009 May 15, 2009 $0.18
May May 31, 2009 June 15, 2009 $0.18
June June 30, 2009 July 15, 2009 $0.18
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For Canadian income tax purposes, the distributions are currently estimated
to be 100 percent taxable income to unitholders.
/T/
16. SUBSEQUENT EVENTS
On July 28, 2009, Zargon announced that it had entered into an Arrangement Agreement pursuant to which Zargon has agreed to make an offer to acquire all the issued and outstanding common shares of Churchill Energy Inc. ("Churchill") and assume approximately $5.80 million of net debt (including transaction costs) subject to a number of conditions. Pursuant to the Arrangement Agreement, Churchill shareholders will have the option of receiving 0.01363 Zargon trust units or $0.22 for each Churchill common share, up to an aggregate maximum of $4.60 million in cash.
17. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to conform with the current year's financial statement presentation.
/T/
CORPORATE INFORMATION
BOARD OF DIRECTORS STOCK EXCHANGE LISTING
Craig H. Hansen Toronto Stock Exchange
Calgary, Alberta
Zargon Energy Trust
K. James Harrison (3) (4) Trust Units
Chairman of the Board Trading Symbol: ZAR.UN
Oakville, Ontario
Zargon Oil & Gas Ltd.
Kyle D. Kitagawa (1) (2) Exchangeable Shares
Calgary, Alberta Trading Symbol: ZOG.B
Geoffrey C. Merritt (2) TRANSFER AGENT
Calgary, Alberta Valiant Trust Company
310, 606 - 4th Street S.W.
Margaret A. McKenzie (1) (3) Calgary, Alberta T2P 1T1
Calgary, Alberta
BANKERS
Jim Peplinski (2) (4) The Toronto Dominion Bank
Calgary, Alberta 910, 333 - 7th Avenue S.W.
Calgary, Alberta T2P 2Z1
J. Graham Weir (1) (2)
Calgary, Alberta Canadian Imperial Bank of Commerce
9th Floor, Bankers Hall East
Grant A. Zawalsky (3) (4) 855 - 2nd Street S.W.
Calgary, Alberta Calgary, Alberta T2P 2P2
OFFICERS The Bank of Nova Scotia
Craig H. Hansen 2000, 700 - 2nd Street S.W.
President and Chief Executive Officer Calgary, Alberta T2P 2N7
Brent C. Heagy LEGAL COUNSEL
Executive Vice President and Burnet, Duckworth & Palmer LLP
Chief Financial Officer 1400, 350 - 7th Avenue S.W.
Calgary, Alberta T2P 3N9
Daniel A. Roulston
Executive Vice President, Engineering CONSULTING ENGINEERS
McDaniel & Associates Consultants
Henry J. Baird Ltd.
Vice President, Exploitation 2220, 255 - 5th Avenue S.W.
Calgary, Alberta T2P 3G6
Jason B. Dranchuk
Controller and Treasurer AUDITORS
Ernst & Young LLP
Tracy L. Howard 1000, 440 - 2nd Avenue S.W.
Corporate Secretary Calgary, Alberta T2P 5E9
Brian G. Kergan HEAD OFFICE
Vice President, Corporate Development 700, 333 - 5th Avenue S.W.
and Reserves Calgary, Alberta T2P 3B6
Telephone: 403-264-9992
Mark I. Lake Fax: 403-265-3026
Vice President, Exploration Email: zargon@zargon.ca
Lorne D. Schwetz WEBSITE
Vice President, Land www.zargon.ca
Al D. Thorsen
Vice President, Operations
(1) Audit Committee
(2) Reserves Committee
(3) Governance and Nominating Committee
(4) Compensation Committee
/T/
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