CALGARY, ALBERTA, Nov. 5, 2009 (Marketwire) -- Cinch Energy Corp. (TSX:CNH) ("Cinch" or "Company") is pleased to report on the Company's activities and financial results for the third quarter of 2009. Highlights are as follows:
HIGHLIGHTS----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 2009 2008
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(Unaudited) (Unaudited) (Unaudited) (Unaudited)
Oil and gas sales,
net of transportation
($000's) 4,403 10,132 16,326 30,945
Sales volumes per day
Natural gas (Mcf/d) 13,044 10,811 13,582 9,675
Natural gas liquids (bbl/d) 207 247 214 261
Equivalence at 6:1 (BOE/d) 2,381 2,049 2,478 1,874
Sales Price
Natural gas ($/Mcf) 2.87 7.97 3.67 9.11
Natural gas liquids ($/bbl) 50.34 96.87 46.51 94.94
Equivalence at 6:1 ($/BOE) 20.10 53.75 24.13 60.28
$ $ $ $
Funds from operations
($000's) (1) 1,854 5,635 7,383 17,085
- per share, basic (1) 0.03 0.10 0.13 0.31
- per share, diluted (1) 0.03 0.10 0.13 0.31
Net income (loss) ($000's) (2,801) 774 (7,367) 2,602
- per share, basic (0.05) 0.01 (0.13) 0.05
- per share, diluted (0.05) 0.01 (0.13) 0.05
Capital expenditures ($000's) 2,301 12,212 5,824 25,329
Basic weighted average shares
outstanding (000's) 56,784 55,628 56,020 55,626
Working capital (net debt)
($000's) (2)
- As at September 30, 2009 (31,040)
- As at December 31, 2008 (35,308)
As at November 4, 2009
Common shares outstanding 58,843,698
Options outstanding 5,881,167
- Weighted average exercise price 1.35
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(1) Funds from operations and funds from operations per share are not
generally accepted accounting principles ("GAAP") and represent cash
provided by operating activities on the statement of cash flows less
the effect of changes in non-cash working capital related to operating
activities.
(2) Net debt is a non-GAAP measure and represents the sum of the working
capital (deficiency) and the outstanding credit facility balance.
President's Message
PRODUCTION, PRICES, AND COSTS
Production for the nine months ended September 30, 2009 averaged approximately 2,478 BOE/d, resulting in a 32% production increase over the same period of 2008, which averaged approximately 1,874 BOE/d. The third quarter of 2009 average production was 2,381 BOE/d which is a 235 BOE/d decrease over the second quarter average production of 2,616 BOE/d. The third quarter production decrease was primarily due to flush production declines from the Dawson 6-6 Wabamun well (85% working interest) which commenced production in March, 2009 at approximately 5 mmcf/d and is currently producing at 3.3 mmcf/d. The Company is very pleased with the production performance of this well as it appears to be stabilizing. The Company's third quarter production reflects normal production declines which were not offset by additional production brought on during the quarter due to the Company curtailing its capital expenditures due to low commodity prices.
Commodity prices in the third quarter of 2009 continued their downward trend from the second quarter of 2009, from $21.90 per BOE to $20.10 per BOE. This decrease is due primarily to a decrease in natural gas prices from $3.25 per mcf to $2.87 per mcf. Natural gas liquids prices increased slightly from $49.55 per barrel to $50.34 per barrel. The market uncertainty continues to make it difficult to predict what commodity prices will be in the near future. Most recently, we have witnessed a strengthening in the oil and natural gas liquids pricing and a significant increase in natural gas prices as the market anticipates the coming winter heating season. In addition, the market appears to be anticipating a balancing of the supply and demand equation in the natural gas scene with the severe down turn in natural gas wells being drilled in 2009. The Company does not have any hedges in place and maintains its balance sheet through rigorous control of its capital expenditures. The Company remains optimistic that natural gas prices will continue to recover during the fourth quarter of 2009 and 2010 year.
Operating expenses in the third quarter of 2009 were $3.04 per BOE as compared to $3.23 per BOE in the second quarter of 2009, primarily due to lower total operating expenses. Operating expenses per BOE are expected to average approximately $4.00 per BOE for 2009, which again is a reduction from the second quarter estimate of $4.25 per BOE.
OPERATIONS
During the third quarter of 2009, Cinch participated in the drilling of three new wells.
In British Columbia, the Company has been active on its Dawson property and is currently drilling the Dawson 6-30 Wabamun test (65% working interest) which was spudded on September 1, 2009. This well is now expected to reach total depth of 3600 metres in the middle of November as drilling operations have been slower than projected. A successful result in this well will greatly assist the Company in supporting its future gas processing development plans for the area. In addition, a development Kiskatinaw well was drilled and completed at Dawson 1-33 (36% working interest). This well was flow tested at rates between 7 - 8 mmcf/d over a 24 hour period. It is expected that this well will commence production in mid December at a rate of 7.8 mmcf/d. Preliminary pressure data and geologic data supports that this well is in the same pool as the Company's previous two producing Kiskatinaw wells located at Dawson 1-32 and 12-27. Based on this geologic and pressure data, the Company anticipates booking additional reserves for the Kiskatinaw pool, which will be evaluated by the Company's external reserve engineers as part of its year end reserve process. This latest well qualifies for the new British Columbia royalty incentives and will be eligible for deep gas royalty holiday and will be paying 2% royalties subsequent to the expiration of the deep gas royalty holiday during its first year of production.
Of significance, Cinch has elected to participate in its first horizontal Montney test to be drilled during the fourth quarter of 2009 (26% working interest). This non-operated well will be drilled in section 22-80-16W6. This is a follow up well to a successful vertical test drilled at 13-23-80-16W6, in which Cinch did not participate.
In Alberta, a well at Kakwa 2-14 (25% working interest) was drilled and cased as a potential gas well. Completion operations are expected to commence shortly.
FINANCIAL
In August 2009, Cinch issued 3.2 million flow-through shares at a price of $0.85 per share for gross proceeds of $2.7 million. These funds are being used to fund the drilling of the exploratory Wabamun well at Dawson 6-30. Current net debt is approximately $31 million, which is a reduction of $2.3 million from the net debt of $33.3 million at the end of the second quarter. Cinch's capital expenditures for the fourth quarter are currently projected to be approximately $4.0 million. The Company continues to closely monitor its future capital commitments which are set to match the Company's cash flow projections. With natural gas prices having improved most recently and capital markets also strengthening, the Company has become more optimistic regarding its future capital programs for the remainder of 2009 and 2010.
George Ongyerth, President
Forward Looking Statements
Statements throughout this release that are not historical facts may be considered to be "forward looking statements." These forward-looking statements sometimes include words to the effect that management believes or expects a stated condition or result. All estimates and statements that describe the Company's objectives, goals, or future plans, including management's assessment of future plans and operations, anticipated commodity prices and their impact, timing of expenditures, use of proceeds from flow-through financing and timing of renunciation, budgeted capital expenditures and the method of funding thereof and the nature of the expenditures, expected cash flows for 2009, timing of phases of the IFRS conversion project, timing of drilling of wells, anticipated results from wells drilled, new incentives under the British Columbia royalty regime and the possible effect thereof on the Company and the economics of the wells to be drilled in that province, expected royalty rates, operating expenses and general and administrative expenses and the expected levels of activities may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, volatility of commodity prices, imprecision of reserve estimates, environmental risks, competition from other producers, incorrect assessment of the value of acquisitions, failure to complete and/or realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources and changes in the regulatory and taxation environment. Consequently, the Company's actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Forward-looking statements or information is based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the ability of the Company to obtain equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which the Company has an interest to operate the field in a safe, efficient and effective manner; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through development of exploration; future oil and natural gas prices; interest rates; the regulatory framework regarding royalties; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included elsewhere herein and in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or at the Company's website (www.cinchenergy.com). Furthermore, the forward-looking statements contained in this release are made as at the date of this release and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.
Barrel of Oil Equivalency
Natural gas volumes are converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (Mcf) of gas to one barrel (bbl) of oil. The term "barrels of oil equivalent" may be misleading, particularly if used in isolation. A BOE conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
MANAGEMENT'S DISCUSSION AND ANALYSIS
November 4, 2009
The following management's discussion and analysis ("MD&A") should be read in conjunction with the unaudited interim financial statements and related notes for the three and nine months ended September 30, 2009 and the audited financial statements and related management discussion and analysis of Cinch Energy Corp. ("Cinch" or the "Company") for the year ended December 31, 2008. Additional information relating to Cinch, including Cinch's Annual Information Form, is available on SEDAR at www.sedar.com.
Non-GAAP Measures
The MD&A contains the term "funds from operations" which should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net income as determined in accordance with Canadian generally accepted accounting principles ("GAAP") as an indicator of the Company's performance. The Company considers funds from operations to be a key measure that demonstrates its ability to generate funds for future growth through capital investment. Funds from operations is calculated by taking cash provided by operating activities on the statement of cash flows less the effect of changes in non-cash working capital related to operating activities. The Company's determination of funds from operations may not be comparable with the calculation of similar measures by other companies. The Company also presents funds from operations per share, where funds from operations are divided by the weighted average number of shares outstanding to determine per share amounts. The Company evaluates its performance based on earnings and funds from operations.
The MD&A contains the term "net debt" which is the sum of the working capital (deficiency) and the outstanding credit facility balance. This number may not be comparable to that reported by other companies.
OPERATIONAL UPDATE
Production for the third quarter of 2009 averaged approximately 2,381 BOE/d, a decrease from the second quarter average production of 2,616 BOE/d. The third quarter production reflects declines on flush production, particularly with respect to the Dawson 6-6 Wabamun well (85% working interest), which produced on average approximately 550 BOE/d (net) during the third quarter of 2009 compared to 670 BOE/d (net) during the second quarter. Third quarter production also reflects declines compared to second quarter production in the Dawson 1-32 well (36% working interest) which declined by an average of approximately 75 BOE/d (net) and the Dawson 12-27 well (38% working interest) which declined by an average of approximately 50 BOE/d (net). Production for the third quarter of 2009 also reflected natural declines, as well as decreases in production resulting from several low-producing, non-operated wells that were shut-in during the quarter.
During the three months ended September 30, 2009, the Company incurred $2.3 million of capital expenditures, the majority of which related to drilling costs for the Dawson 6-30 Wabamun well (65% working interest), as well as the Dawson 1-33 Kiskatinaw well (36% working interest). The Company exited the quarter with net debt of $31.0 million, $26.9 million of which was drawn on its $43.0 million demand bank credit facility.
PRODUCTION----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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Sales volumes % %
Natural gas (Mcf/d) 13,044 10,811 21 13,582 9,675 40
Liquids (bbl/d) 207 247 (16) 214 261 (18)
Equivalence (BOE/d) 2,381 2,049 16 2,478 1,874 32
Sales prices $ $ % $ $ %
Natural gas ($/Mcf) 2.87 7.97 (64) 3.67 9.11 (60)
Liquids ($/bbl) 50.34 96.87 (48) 46.51 94.94 (51)
Equivalence ($/BOE) 20.10 53.75 (63) 24.13 60.28 (60)
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Sales volumes for the three and nine months ended September 30, 2009, increased 16% and 32%, respectively, over the same periods of 2008 due to seven additional wells brought on during the latter half of 2008 and the first part of 2009. The most significant were the Dawson 12-27 (38% working interest) and the Dawson 6-6 (85% working interest) wells, which came on production in late October, 2008 and late March, 2009, respectively. Despite declines in production from these wells during the third quarter of 2009, the wells continue to produce at a combined rate of over 700 BOE/d (net).
Natural gas prices were 64% and 60% lower for the three and nine months ended September 30, 2009, respectively, compared to the same periods in 2008. Natural gas prices for the third quarter of 2009 were 12% lower than the second quarter of 2009. The Company's natural gas production continues to be unhedged and is marketed in the Alberta spot market.
Natural gas liquids pricing was 48% and 51% lower for the three and nine months ended September 30, 2009, respectively, compared to the same periods in 2008. Natural gas liquids pricing for the third quarter of 2009 was slightly higher than the $49.55/bbl reported during the second quarter of 2009. Natural gas liquids represent approximately 9% of the Company's oil and natural gas production. The Company has not hedged any of its liquids production.
REVENUESDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Oil and gas sales,
net of transportation 4,403 10,132 (57) 16,326 30,945 (47)
Per BOE 20.10 53.75 (63) 24.13 60.28 (60)
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Revenues for the three and nine months ended September 30, 2009 were 57% and 47% lower, respectively, than the same periods of 2008 due to significantly lower commodity prices, partially offset by higher production, as previously discussed. Transportation expense decreased by approximately $0.17 per BOE for the first nine months of 2009 compared to the same period of 2008 primarily due to lower transportation fees in British Columbia, which had minimal production during the first half of 2008.
Revenues for the three months ended September 30, 2009, have decreased 16% from the second quarter of 2009 as a result of lower natural gas prices and lower production during the third quarter of 2009.
ROYALTIESDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Royalties 720 2,434 (70) 3,036 7,782 (61)
Per BOE 3.29 12.91 (75) 4.49 15.16 (70)
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Royalty expense decreased during the three and nine months ended September 30, 2009 compared to the same periods of 2008 primarily due to lower revenues, as well as royalty holidays received on some producing wells. The New Royalty Framework ("NRF"), which became effective on January 1, 2009 in Alberta has also impacted royalty expense in 2009 whereby the low natural gas prices experienced during the first nine months of 2009 have resulted in a lower corporate royalty rate. As the natural gas prices increase, the corporate royalty rate is expected to increase.
Royalty expense for the third quarter of 2009 was marginally higher than the $706 thousand of royalty expense recorded during the second quarter of 2009 primarily due to the expiration of the royalty holiday on the Dawson 6-6 well in the second quarter. The increase in royalty expense was partially offset by lower revenues received during the third quarter of 2009. The royalty rate (royalties as a percentage of oil and gas sales) for the third quarter of 2009 was approximately 16.3%, compared to the preceding quarter's rate of approximately 13.5%. The higher rate reflects royalties paid on the Dawson 6-6 well, which was no longer eligible for royalty holiday in the third quarter of 2009. Partially offsetting this rate increase was the continued decline in natural gas prices resulting in a lower overall corporate royalty rate in Alberta. The royalty rate is comprised of both crown royalties and gross overriding royalties.
The royalty rate for the remainder of 2009 is anticipated to be higher than the rate experienced year to date due to higher anticipated commodity prices in the fourth quarter of 2009. Anticipated royalty rates can change, however, depending upon commodity prices, actual success achieved and the zone in which productive success is achieved.
OPERATING EXPENSESDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Operating 666 1,130 (41) 2,489 3,111 (20)
Per BOE 3.04 5.99 (49) 3.68 6.06 (39)
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Total operating expenses for the three and nine months ended September 30, 2009 decreased by 41% and 20%, respectively, compared to the same periods in 2008 primarily due to a gas processing credit received from the Alberta Government under the NRF, as well as lower compressor and equipment maintenance costs and lower methanol and chemical treating costs in 2009. These decreases in operating expenses were partially offset by higher property taxes during 2009.
Operating expenses per BOE for the three and nine months ended September 30, 2009, decreased 49% and 39%, respectively, compared to the same periods of 2008 primarily due to a gas processing credit received in 2009, as well as increased production during 2009.
Total operating expenses for the third quarter of 2009 were lower than the second quarter of 2009 due to lower methanol and chemical treating costs and fluid analysis costs, partially offset by higher compressor and equipment maintenance costs and a decrease in the gas processing credit received during the third quarter. Operating expenses for the third quarter of 2009 were $3.04 per BOE, compared to the second quarter at $3.23 per BOE, primarily due to lower total operating expenses.
Operating expenses for 2009 are not expected to exceed $4.00 per BOE. This is a decrease from the prior guidance of $4.25 per BOE, which can mostly be attributed to increased operational efficiencies. Operating expenses per BOE are expected to increase during the fourth quarter of 2009 primarily due to lower expected production during this period, as well as anticipated increases in methanol charges and maintenance costs. Anticipated costs per BOE can change however, depending on the Company's actual production levels and future changes to the gas processing credits the Company currently receives.
GENERAL AND ADMINISTRATIVE EXPENSESDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
General and administrative 967 834 16 2,937 2,683 9
Per BOE 4.42 4.42 - 4.34 5.23 (17)
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Total general and administrative expenses increased for the three and nine months ended September 30, 2009 compared to the same periods of 2008 due to increased salaries and wages, contractor costs, legal fees, and higher bank charges relating to the Company's credit facility. The increased contractor costs were a direct result of the work performed on the implementation of International Financial Reporting Standards ("IFRS"), as discussed in the recent accounting pronouncements section below. The Company does not capitalize indirect general and administrative expenses.
General and administrative expenses per BOE for the third quarter of 2009 were consistent with the same period of 2008 notwithstanding the increase in total general and administrative expenses due to the higher production volumes in 2009. General and administrative expenses per BOE for the nine months ended September 30, 2009 were lower than the same period of 2008 due to increased production volumes in 2009.
Total general and administrative expenses in the third quarter of 2009 were consistent with the preceding second quarter. General and administrative expenses per BOE were 7% higher in the third quarter of 2009 at $4.42/BOE compared to the second quarter due to decreased production during the third quarter.
General and administrative expenses for 2009 are not expected to exceed $4.50 per BOE. Anticipated costs per BOE can change, however, depending on the Company's actual production levels.
INTEREST EXPENSEDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Interest expense 295 263 12 821 833 (1)
Per BOE 1.35 1.39 (3) 1.21 1.62 (25)
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Interest expense increased during the three months ended September 30, 2009 compared to the same period in 2008 due to higher draws on the Company's bank credit facility during the third quarter of 2009. Interest expense decreased during the nine months ended September 30, 2009 compared to the same period of 2008, as a result of lower interest rates partially offset by a higher average balance drawn on the Company's bank credit facility throughout the first nine months of 2009. The Company exited the quarter with an outstanding credit facility balance of $26.9 million on its $43.0 million credit facility.
ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSEDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Accretion expense 57 48 19 166 141 18
Per BOE 0.26 0.26 - 0.25 0.28 (11)
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Accretion expense increased during the three and nine months ended September 30, 2009 compared to the same periods in 2008 due to an increased number of wells with asset retirement obligations.
DEPLETION AND DEPRECIATION EXPENSEDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Depletion and depreciation 5,460 4,385 25 16,871 12,876 31
Per BOE 24.93 23.26 7 24.94 25.08 (1)
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Total depletion and depreciation expense for the three and nine months ended September 30, 2009 increased compared to the same periods of 2008 due to increased production, as well as a larger capital asset base being depleted. Depletion per BOE for the three months ended September 30, 2009 increased compared to the same period of 2008 primarily due to a reduction in the reserve base used to calculate depletion. Depletion per BOE for the nine months ended September 30, 2009 is consistent with the depletion per BOE for the comparable period in 2008.
The depletion and depreciation expense decreased $481 thousand during the third quarter of 2009 compared to the preceding second quarter primarily due to lower production.
TAXESDollars in thousands, except per unit amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Future income
tax expense (recovery) (953) 308 (409) (2,588) 1,032 (351)
Per BOE (4.35) 1.64 (365) (3.83) 2.01 (291)
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A future income tax recovery was recorded for the three and nine months ended September 30, 2009 which is consistent with the net loss experienced during the quarter and on a year to date basis.
Tax pools at September 30:In thousands
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2009 2008
$ $
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COGPE 14,737 15,781
CDE 22,551 27,394
CEE 33,093 24,397
UCC 16,564 17,942
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86,945 85,514
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The Company's tax pools have increased since September 30, 2008 as a result of capital expenditures which were higher than the tax pools needed to eliminate taxable income.
NET INCOME (LOSS) AND FUNDS FROM OPERATIONSIn thousands, except per share amounts
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Three Months Ended Nine Months Ended
September 30, September 30,
2009 2008 Change 2009 2008 Change
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$ $ % $ $ %
Net income (loss) (2,801) 774 (462) (7,367) 2,602 (383)
per basic share (0.05) 0.01 (600) (0.13) 0.05 (360)
per diluted share (0.05) 0.01 (600) (0.13) 0.05 (360)
Funds from operations 1,854 5,635 (67) 7,383 17,085 (57)
per basic share 0.03 0.10 (70) 0.13 0.31 (58)
per diluted share 0.03 0.10 (70) 0.13 0.31 (58)
Weighted average
shares outstanding 56,784 55,628 2 56,020 55,626 1
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For the three and nine months ended September 30, 2009, the Company incurred a net loss primarily attributable to lower commodity prices.
The Company's funds from operations for the three and nine months ended September 30, 2009 decreased by 67% and 57%, respectively, over the same periods of 2008.
