2008-08-07 15:01:00
Cinch Energy Corp. Releases Second Quarter 2008 Results
CALGARY, ALBERTA–(EMWNews – Aug. 7, 2008) – Cinch Energy Corp. (“Cinch” or “Company”) (TSX:CNH) is pleased to report on the Company’s activities and financial results for the second quarter of 2008. Highlights are as follows:
HIGHLIGHTS
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Three Months Ended Six Months Ended
June 30, June 30,
2008 2007 2008 2007
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(Unaudited) (Unaudited) (Unaudited) (Unaudited)
Petroleum and natural gas
sales, net of transportation
($000's) 12,676 5,582 20,813 11,698
Sales volumes per day
Natural gas (Mcf/d) 10,302 6,157 9,101 6,472
Natural gas liquids (Bbl/d) 274 223 268 222
Equivalence at 6:1 (BOE/d) 1,991 1,249 1,785 1,301
Sales Price
Natural gas ($/Mcf) 10.74 7.75 9.80 7.90
Natural gas liquids ($/Bbl) 104.46 61.15 94.04 60.84
Equivalence at 6:1 ($/BOE) 69.97 49.11 64.08 49.68
$ $ $ $
Funds from operations
(000's) (1) 7,320 2,589 11,451 5,960
- per share, basic (1) 0.13 0.05 0.21 0.11
- per share, diluted (1) 0.13 0.05 0.21 0.11
Net income (loss) (000's) 1,810 (709) 1,827 (978)
- per share, basic 0.03 (0.01) 0.03 (0.02)
- per share, diluted 0.03 (0.01) 0.03 (0.02)
Capital expenditures ($000's) 4,584 3,930 13,117 10,158
Basic weighted average shares
outstanding (000's) 55,625 55,570 55,625 53,326
Working capital (net debt)
(2) ($000's)
- As at June 30, 2008 (26,424)
- As at December 31, 2007 (24,758)
As at August 6, 2008
Common shares outstanding 55,625,132
Options outstanding 4,716,500
- Weighted average exercise price 1.65
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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
The Dawson, B.C. area continues to have a significant impact on Cinch’s production as the Dawson 1-32 well, since commencement of production has produced in excess of 10 mmcf/d and, to date, shows minimal signs of decline. This well has increased Cinch’s production average in the second quarter to 1,991 BOE/d, as compared to 1,579 BOE/d in the first quarter of 2008. Production for the six months ended June 30, 2008 averaged 1,785 BOE/d as compared to 1,301 BOE/d in the comparable period of 2007. Production is currently approximately 1,950 BOE/d with an additional 400 BOE/d expected to be added by September 2008.
Commodity prices for the second quarter of 2008 increased significantly over the first quarter, from $56.63 per BOE to $69.97 per BOE. This increase is due to both an increase in the natural gas price increasing from $8.55 per mcf to $10.74 per mcf, and natural gas liquids increasing from $83.16 per barrel to $104.46 per barrel. The Company does not have any hedges in place and remains positive about commodity prices in the future, notwithstanding that there has been a slight pull back in prices recently.
Operating costs in the second quarter of 2008 were $6.24 per BOE as compared to $5.92 per BOE in the first quarter, primarily due to an increase in processing fees, as well as property taxes being paid in the second quarter. Operating expenses per BOE for the first and second quarters of 2008 decreased slightly as compared to the same periods in 2007 due to an increase in production volumes.
OPERATIONS
During the second quarter of 2008, Cinch participated in the drilling of 2 wells both of which were cased as gas wells. Two additional wells were also drilling at time of this report.
At Dawson, B.C. the Dawson 12-27 Kiskatinaw gas well (38.2% working interest) was completed and flow tested. During a two day flow test the well was flowed at a stable rate of 6.1 mmcf/d. The flowing pressures were very similar to the Dawson 1-32 well, which has been on production since April 2008. Production from both the Dawson 13-11 and Dawson 12-27 wells is expected to commence in September as obtaining pipeline right-of-ways from surface owners has been prolonged for various issues. The Dawson 6-6 well (85% working interest) has been deepened to evaluate a Wabamun prospect. Cinch and its partners are planning to drill four additional Kiskatinaw tests and two horizontal Montney tests before the end of the year. The first Kiskatinaw well of this program is expected to spud in late August and is located at 6-1-81-16W6. This location offsets the Parkland Montney pool and is a dual-zone prospect. A surface lease has also been taken to drill a horizontal Montney well in this section after the Dawson 6-1 Kiskatinaw test has been logged. By drilling deeper multi-zone prospective locations, Cinch is reducing the risks of drilling horizontal wells in the Montney. In addition to this drilling program, two proposed recompletions in the Montney zone within existing cased wells are currently being considered.
At Chime, the Company has participated in the drilling of the Chime 14-6 location (40% working interest), which has been cased as a potential gas well.
In the Kakwa E pool, Cinch has finished drilling and casing two Dunvegan development wells (45% working interest) as gas wells. A third well was spud at the end of July 2008. The first well, Kakwa 3-7 has now been completed and flow tested at 2.1 mmcf/d. It is expected that this well will commence production in mid-August.
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, budgeted capital expenditures and the method of funding thereof, timing of drilling, completion and tie-in of wells, expected production additions and the timing thereof, expected royalty rates and changes to the Alberta royalty regime and the possible effect thereof on the Company and its allocation of capital, expected royalty rates, operating costs 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. As a consequence, the Company’s actual results may differ materially from those expressed in, or implied by, the forward-looking statements. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect.
Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this document, assumptions have been made regarding, among other things: the ability of the Company to obtain equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manor; 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
August 6, 2008
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 six month periods ended June 30, 2008 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, 2007. 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
For the second quarter of 2008, the Company successfully increased production, as well as revenues and cash flows over the prior quarter. The Company’s production averaged approximately 1,991 BOE/d in the second quarter resulting in a 26% increase over the first quarter production of 1,579 BOE/d. The revenues and cash flows also increased 56% and 77%, respectively, over the first quarter due to increased production and increased commodity prices. The production increase in the second quarter is mostly attributable to the Dawson 1-32 well, in which Cinch holds a 36% working interest, which came on production in mid-April 2008 at rates of approximately 10 mmcf/d (gross). This well has added approximately 600 BOE/d (net) to Cinch’s daily production.
Funds from operations for the second quarter of 2008 were $7.3 million, exceeding that of any prior quarters, as a result of increased production, as well as higher commodity prices.
For the three months ended June 30, 2008, the Company incurred $4.6 million of capital expenditures exiting the quarter with net debt of $26.4 million, $21.7 million of which is drawn on its $34 million demand bank credit facility. The net debt at June 30, 2008 decreased $2.8 million from the net debt at March 31, 2008 due to increased cash flows generated.
In the third quarter of 2008, the Company plans to drill, complete and tie-in multiple locations primarily in the Dawson, Kakwa and Chime areas. At Dawson, the Dawson 12-27, and the Dawson 13-11 wells have been completed and are awaiting surface owner approvals for the tie-ins expected to occur in August/September. At Kakwa, the Company has drilled and cased two wells, with a third well that spud at the end of July 2008. All three wells are anticipated to be tied-in before the end of the third quarter, pending results. At Chime, the Chime 14-6 well has been cased as a potential gas well.
PRODUCTION
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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Sales volumes % %
Natural gas (mcf/d) 10,302 6,157 67 9,101 6,472 41
Liquids (bbl/d) 274 223 23 268 222 20
Equivalence (BOE/d) 1,991 1,249 59 1,785 1,301 37
Sales prices $ $ % $ $ %
Natural gas ($/Mcf) 10.74 7.75 39 9.80 7.90 24
Liquids ($/Bbl) 104.46 61.15 71 94.04 60.84 55
Equivalence ($/BOE) 69.97 49.11 42 64.08 49.68 29
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Sales volumes for the three and six months ended June 30, 2008, increased over the same periods of 2007 due to seven additional wells brought on production since June 2007. The most significant well, which came on production in mid April 2008, was the Dawson 1-32 well, averaging approximately 600 BOE/d (net).
Natural gas prices were 39% and 24% higher for the three and six months ended June 30, 2008, respectively, compared to the same periods of 2007. Natural gas prices for the second quarter of 2008 were 26% higher than the first quarter of 2008. Natural gas prices did decrease subsequent to the quarter end but are still expected to remain strong for the remainder of 2008. The Company’s natural gas production continues to be unhedged and is marketed in the Alberta spot market.
Natural gas liquids pricing was 71% and 55% higher for the three and six months ended June 30, 2008, respectively, compared to the same periods of 2007. Natural gas liquids pricing for the second quarter of 2008 was 26% higher than the first quarter of 2008. Natural gas liquids represent approximately 14% of the Company’s oil and gas production. The Company has not hedged any of its liquids production.
REVENUES
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Oil and gas
net of sales,
transportation 12,676 5,582 127 20,813 11,698 78
Per BOE 69.97 49.11 42 64.08 49.68 29
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Revenues for the three and six months ended June 30, 2008 were 127% and 78% higher, respectively, than the same periods of 2007 due to higher production, as well as higher commodity prices, as previously discussed. Transportation expense per BOE for the first six months of 2008 was consistent with 2007.
Revenues for the three months ended June 30, 2008, have increased 56% from the first quarter of 2008, as a result of higher production, as well as higher commodity prices.
ROYALTIES
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Royalties 3,271 1,397 134 5,348 2,396 123
Per BOE 18.06 12.30 47 16.46 10.18 62
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Royalty expense increased in the three and six months ended June 30, 2008 compared to the same periods of 2007 primarily due to higher revenues, as well as the expiration of royalty holidays on some higher producing wells.
Royalty expense for the second quarter of 2008 increased over the first quarter of 2008 mostly due to higher revenues. The royalty rate for the second quarter of 2008 (royalties as a percentage of oil and gas sales), is consistent with that of the prior quarter at approximately 26%. This rate is comprised of both crown royalties and gross overriding royalties.
The royalty rate for the remainder of 2008 is not expected to change substantially from the royalty rate experienced in the first half of the year. Management further anticipates an increase in the royalty rate effective January 1, 2009 when the proposed Alberta royalty framework is implemented. Anticipated royalty rates can change however, depending upon commodity prices, actual success achieved and the zone in which productive success is achieved
Impact of the new Alberta royalty framework
Management of the Company has reviewed the new proposed Alberta Royalty Framework (“NRF”). Although, the Company has a significant number of prospects in the province of Alberta, management believes that the proposed royalty changes would result in unacceptable rates of return for some of the Company’s deep gas prospects in Alberta. In April 2008, the government released changes to the proposed NRF due to “unintended consequences”, especially as they relate to deep oil and deep gas drilling. These changes resulted in increased deep gas drilling incentives compared to the initial release of the NRF. Under these proposed changes, there will be some deep gas royalty holiday incentives provided, with increased incentives for wells deeper than 4,000 meters. Most of Cinch’s wells range in depths from 2,300 to 3,500 meters and the incentives provided for those wells has decreased compared to the current incentives. Based on its assessment resulting from the current information, Cinch has allocated a larger portion of its capital spending to the Dawson Area of British Columbia, where royalty rates are more favorable.
OPERATING EXPENSES
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Operating 1,130 716 58 1,982 1,469 35
Per BOE 6.24 6.30 (1) 6.10 6.24 (2)
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Total operating expenses for the three and six months ended June 30, 2008 increased compared to the same periods of 2007 due to increased gas processing fees, compression fees, compressor and equipment maintenance, insurance, and property taxes. Operating expenses per BOE for the three and six months ended June 30, 2008, decreased compared to the same periods of 2007 due to increased production.
Total operating expenses for the second quarter of 2008 were higher than the first quarter due to increased gas processing fees, as well as property taxes recorded in the second quarter. Operating expenses per BOE were higher than those experienced in the first quarter of 2008 at $6.24/BOE due to higher fixed costs incurred in the second quarter. These costs are not expected to be incurred to the same extent for the second half of 2008.
Operating expenses per BOE are expected to continue to decrease in the second half of 2008 and are not expected to exceed $5.75 per BOE in 2008. Costs per BOE may change, however, depending on the Company’s actual production levels.
GENERAL AND ADMINISTRATIVE EXPENSES
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
General and
administrative 862 950 (9) 1,850 2,021 (8)
Per BOE 4.76 8.36 (43) 5.69 8.58 (34)
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Total general and administrative expenses decreased for the three and six months ended June 30, 2008 compared to the same periods of 2007 due to decreased stock based compensation expense, as well as lower contractor and consultant fees partially offset by higher computer support and software charges. For the six months ended June 30, 2008, overhead recoveries were also $76 thousand higher than 2007 due to a change in the mix of operated versus non-operated activities, resulting in a direct reduction of general and administrative expenses. The Company does not capitalize indirect general and administrative expenses. General and administrative expenses per BOE were lower for the three and six months ended June 30, 2008 compared to the same periods of 2007 due to lower general and administrative expenses over higher production in 2008.
Total general and administrative expenses decreased approximately $125 thousand in the second quarter of 2008 compared to the first quarter mostly due to lower stock based compensation expense; public company related expenses, as well as lower recruitment fees. The decrease in general and administrative expenses is partially offset by decreased overhead recoveries ($27k) in the second quarter of 2008. General and administrative expenses per BOE were 31% lower in the second quarter of 2008 at $4.76/BOE compared to the first quarter due to lower expenses and higher production in the second quarter.
General and administrative expenses for 2008 are not expected to exceed $5.75 per BOE. Anticipated costs per BOE can change, however, depending on the Company’s actual production levels.
INTEREST EXPENSE
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Interest expense 269 196 37 570 426 34
Per BOE 1.49 1.73 (14) 1.76 1.81 (3)
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Interest expense increased in the three and six months ended June 30, 2008 compared to the same periods of 2007 due to higher draws on the Company’s bank credit facility in 2008. The Company exited the quarter with an outstanding credit facility balance of $21.7 million on its $34 million credit facility. In 2007, the Company exited the second quarter with an amount outstanding under its credit facility of $14.2 million.
ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Accretion expense 46 44 5 93 85 9
Per BOE 0.25 0.39 (36) 0.29 0.36 (19)
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Accretion expense increased in the three and six months ended June 30, 2008 compared to the same periods of 2007 due to an increase in the number of wells with asset retirement obligations as a result of drilling operations.
DEPLETION AND DEPRECIATION EXPENSE
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Depletion and
depreciation 4,674 3,189 47 8,491 6,495 31
Per BOE 25.80 28.05 (8) 26.14 27.58 (5)
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Total depletion and depreciation expense for the three and six months ended June 30, 2008 increased compared to the same periods of 2007 due to increased production, as well as a larger capital asset base being depleted. Depletion per BOE for the three and six months ended June 30, 2008 decreased compared to the same period of 2007 due to positive drilling results resulting in reserve additions.
The depletion and depreciation expense increased in the second quarter of 2008 compared to the first quarter of 2008 by approximately $857 thousand due to higher production and a larger capital asset balance being depleted partially offset by reserve additions.
TAXES
Dollars in thousands, except per unit amounts
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Future income tax
expense (recoveries) 657 (192) 442 724 (183) 496
Per BOE 3.62 (1.69) 314 2.23 (0.78) 386
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A future income tax expense was recorded in the three and six months ended June 30, 2008 commensurate with the net income experienced in the quarter.
Tax pools at June 30:
In thousands
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2008 2007
$ $
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COGPE 13,842 13,773
CDE 25,599 21,101
CEE 21,387 25,471
UCC 17,845 19,840
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78,673 80,185
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The Company’s tax pools have decreased since June 30, 2007 as a result of an equity financing completed on February 21, 2007 for flow-through common shares of $10 million. This amount has been deducted from the tax pools as the flow-through expenditures were renounced in January 2008, effective December 31, 2007. As at June 30, 2008, all the required expenditures had been incurred.
NET INCOME (LOSS) AND FUNDS FROM OPERATIONS
In thousands, except per share figures
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Three Months Ended June 30, Six Months Ended June 30,
2008 2007 Change 2008 2007 Change
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$ $ % $ $ %
Net income (loss) 1,810 (709) 355 1,827 (978) 287
per basic share 0.03 (0.01) 355 0.03 (0.02) 279
per diluted share 0.03 (0.01) 353 0.03 (0.02) 279
Funds from operations 7,320 2,589 183 11,451 5,960 92
per basic share 0.13 0.05 160 0.21 0.11 88
per diluted share 0.13 0.05 160 0.21 0.11 88
Weighted average
shares outstanding 55,625 55,570 - 55,625 53,326 4
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For the three and six months ended June 30, 2008, the Company generated net income attributable to increased production and higher commodity prices.
The Company’s funds from operations for the three and six months ended June 30, 2008 increased by 183% and 92%, respectively, over the same periods of 2007. Funds from operations in 2008 are higher due to increased revenues as a result of higher production levels, as well as higher commodity prices.
LIQUIDITY AND CAPITAL RESOURCES
In thousands
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June 30, December 31,
2008 2007 Change
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$ $ %
Working capital (deficiency), (4,755) (4,168) 14
excluding credit facility
Credit facility (21,669) (20,589) 5
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Net debt (26,424) (24,758) 7
Shareholders' equity (84,932) (85,315) -
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At June 30, 2008, the Company had net debt of $26.4 million, comprised of a working capital deficiency of $4.7 million and an amount outstanding on its credit facility of $21.7 million. The $1.7 million increase in net debt from December 31, 2007 can be attributed to capital expenditures of $13.1 million partially offset by funds from operations for the six months ended June 30, 2008 of $11.4 million.
Management currently intends to fund the remainder of its 2008 capital program with a combination of funds generated from operations and its bank credit facility. Management monitors and updates its forecast to incorporate changes in capital, actual results and commodity market pricing, and has forecast that it has sufficient access to capital to carry out the planned 2008 program. At June 30, 2008, the Company had $21.7 million outstanding on its $34.0 million demand bank credit facility.
The decrease in shareholder’s equity at June 30, 2008 from December 31, 2007 is due to the tax effect of $10 million in flow-through share expenditures renounced in January 2008 on flow-through shares issued in February 2007 partially offset by net income realized in 2008.
CAPITAL EXPENDITURES
Additions to property, plant and equipment
In thousands
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Six months ended June 30,
2008 2007
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$ $
Land and rentals 1,213 1,964
Seismic 998 267
Drilling, completing and equipping 8,884 6,847
Pipelines and facilities 1,693 992
Other assets 329 88
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Total 13,117 10,158
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Capital expenditures for the six months ended June 30, 2008 include approximately $1.0 million relating to land acquisitions in the Dawson and Kakwa areas. The remaining capital additions were incurred primarily on drilling, completing and tieing-in locations in the Dawson, Kakwa and Chime areas. At June 30, 2008, based on an internal evaluation, additional reserves were added through drilling and completion operations in the Dawson area.
Management’s primary strategy is to expend capital on exploration and development drilling and earn land by drilling. The Company may, however, also purchase land where considered strategic.
BUSINESS RISKS AND RISK MANAGEMENT
The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Cinch attempts to reduce risk in accomplishing these goals through the combination of hiring experienced and knowledgeable personnel and careful evaluation.
The Company’s program is exploratory in nature and in areas with deep, tight gas. The wells the Company drills therefore tend to be deep (a substantial portion are deeper than 2,500 meters), and are subject to higher drilling costs than those in more shallow areas. In addition, most wells require fracture treatment before they are capable of production, also increasing costs. The Company mitigates the additional economic pressure that this creates by carefully evaluating risk/reward scenarios for each location, by taking what management considers to be appropriate working interests after considering project risk, by practicing prudent operations so that drilling risk is decreased, by ranking and limiting the zones that the Company is willing to complete, and also by drilling deep so that the multi-zone potential of the area can be accessed and potentially developed. The Company operates the majority of its lands, which provides a measure of control over the timing and location of capital expenditures. In addition, the Company monitors capital spending on an ongoing and regular basis in order to maintain liquidity.
The financial capability of the Company’s partners can pose a risk to the Company, particularly during periods when access to capital is more challenging and prices are depressed. The Company mitigates the risk of collection by attempting to obtain the partners share of capital expenditures in advance of a project and by monitoring receivables regularly. The ability of the Company to implement its capital program when the financial wherewithal of a partner is challenged can be more difficult, although the Company attempts to mitigate the risk by cultivating multiple business relationships and obtaining new partners when needed and where possible.
Commodity price fluctuations can pose a risk to the Company, and management monitors these on an ongoing basis. External factors beyond the Company’s control may affect the marketability of the natural gas and natural gas liquids produced. The Company has not to date implemented any hedging instruments.
The Company has selected the appropriate personnel to monitor operations and has automated field information where possible, so that difficulties and operational issues can be assessed and dealt with on a timely basis, and so that production can be maximized as much as possible. Not all operational issues; however, are within the Company’s control. Management will address them nonetheless, and attempt to implement solutions, which may be by their nature longer term.
Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, and spills, each of which could result in damage to wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, the Company insures against most of these risks (although not all such risks are insurable). The Company maintains liability insurance in an amount that it considers consistent with industry practice although the nature of these risks is such that liabilities could potentially exceed policy limits. The Company also reduces risk by operating a large percentage of its operations. As such, the Company has control over the quality of work performed and the personnel involved.
The Company anticipates making substantial capital expenditures in the future for the exploration, development, acquisition and production of oil and natural gas reserves. If the Company’s revenues or reserves decline, it may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing will be available. The Company mitigates this risk by monitoring expenditures, operations and results of operations in order to manage available capital effectively.
Attracting and retaining qualified individuals is crucial to the Company’s success. The Company understands the importance of maintaining competitive compensation levels given the competitive environment in which the Company operates. The inability to attract and retain key employees could have a material adverse effect on the Company.
The Company’s ability to move heavy equipment in the field is dependent on weather conditions. Rain and snow can impact conditions, and many secondary roads and future oil and gas production sites are incapable of supporting the weight of heavy equipment until the roads are thoroughly dry. The duration of difficult conditions has a direct impact on the Company’s activity levels and as a result can delay operations.
The Government of Alberta has announced its new proposed royalty framework. The Company will continue to monitor the impact of the new royalty framework on its operations and reassess operational plans as necessary. Currently, the majority of Cinch’s production is in Alberta but given the current proposed royalty changes, Cinch’s 2008 capital budget reflects reduced spending in Alberta and increased spending in British Columbia where royalty rates are more favorable.
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. In 2002, the Government of Canada ratified the Kyoto Protocol (the “Protocol”), which calls for Canada to reduce its greenhouse gas emissions to specified levels. There has been much public debate with respect to Canada’s ability to meet these targets and the Government’s strategy or alternative strategies with respect to climate change and the control of greenhouse gases. The Federal Government has introduced legislation aimed at reducing greenhouse gas emissions using an “intensity based” approach, the specifics of which have yet to be determined. Bill C-288, which is intended to ensure that Canada meets its global climate change obligations under the Kyoto Protocol, was passed by the House of Commons on February 14, 2007.
On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the “Action Plan”), also known as ecoACTION which includes the Regulatory Framework for Air Emissions. This Action Plan covers not-only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not currently possible to predict either the nature of those requirements or the impact on the Company and its operations and financial condition. The Company optimizes its operations with respect to compressor fuel usage and natural gas flaring so that a reduction in emissions is realized.
On March 10, 2008, the Government of Canada released “Turning the Corner – Taking Action to Fight Climate Change”, (the “Updated Action Plan”) which provides some additional guidance with respect to the Government’s plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. Details of the Updated Action Plan are provided in the Company’s Annual Information Form for the year ended December 31, 2007.
DISCLOSURE CONTROLS AND PROCEDURES
The Company has designed disclosure controls and procedures to provide reasonable assurance that material information relating to the Company required to be disclosed is recorded, processed, summarized and reported within the time periods specified by securities regulations and that information required to be disclosed is communicated to management on a timely basis.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The Company’s Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting relating to the Company to provide reasonable assurance regarding the reliability of the Company’s financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP.
The Company’s Chief Executive Officer and Chief Financial Officer are required to cause the Company to disclose any change in the Company’s internal controls over financial reporting that occurred during the Company’s most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting. No material changes in the Company’s internal controls over financial reporting were identified during the three months ended June 30, 2008, that have materially affected, or are reasonably likely to affect, the Company’s internal controls over financial reporting.
The Chief Executive Officer and Chief Financial Officer have signed form 52-109F2- Certification of Interim Filings, which can be found on SEDAR at www.sedar.com.
CONTRACTUAL OBLIGATIONS, COMMITMENTS, AND GUARANTEES
The Company has contractual obligations and commitments in the normal course of its operating and financing activities. These obligations and commitments have been considered when assessing the Company’s cash requirements in its analysis of future liquidity.
Dollars in thousands
----------------------------------------------------------------------------
Payments
Total less than 1-3 4-5 greater
1 year years years than 5
years
Operating lease 293 207 86 - -
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293 207 86 - -
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CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2008 the Company adopted the CICA Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments – Disclosures, Handbook Section 3863, Financial Instruments – Presentation and Handbook Section 1400, General Standards of Financial Statement Presentation. The adoption of Section 1535 resulted in additional disclosure with regard to the Company’s objectives, policies and processes for managing capital. The adoption of Sections 3862 and 3863 did not impact the classification and valuation of the Company’s financial instruments due to the nature of the financial instruments recorded on the balance sheet and the contracts to which the Company is a party to. The adoption of Section 1400 did not have an impact on the Company due to the fact that management has always assessed the Company’s ability to continue as a going concern. For more information on these policies, see note 2 of the Company’s financial statements for the three and six months ended June 30, 2008.
RECENT ACCOUNTING PRONOUNCEMENTS
The Canadian Institute of Chartered Accountants (CICA) has issued a number of accounting pronouncements, some of which may impact the Company’s reported results and financial position in future periods.
On February 13, 2008, the Canadian Accounting Standards Board (AcSB) confirmed the use of International Financial Reporting Standards (“IFRS”) for publicly accountable profit-oriented enterprises beginning on January 1, 2011 with appropriate comparative data from the prior year. IFRS will replace Canadian GAAP for those enterprises. These include listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Under IFRS, the primary audience is capital markets and as a result, there is significantly more disclosure required, specifically for quarterly reporting. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policies which must be addressed. The impact of these new standards on our financial statements is currently being assessed.
CRITICAL ACCOUNTING ESTIMATES
There are a number of critical estimates underlying the accounting policies the Company applies in preparing its financial statements.
Reserves
The estimate of reserves is used in forecasting what will ultimately be recoverable from the properties and their economic viability and in calculating the Company’s depletion and potential impairment of asset carrying costs. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering and economic data.
Reserves at year end are evaluated by an independent engineering firm and quarterly updates to those reserves are estimated by the Company.
Revenue Estimates
Payment and actual amounts for petroleum and natural gas sales can be received months after production. The Company estimates a portion of its petroleum and natural gas production, sales and related costs, based upon information received from field offices, internal calculations, historical and industry experience.
Cost Estimates
Costs for services performed but not yet billed are estimated based on quotes provided and historical and industry experience.
Asset Retirement Obligations
The liability recorded for asset retirement obligations, an estimate of restoring assets and locations back to environmental and regulatory standards upon future retirement or abandonment, include estimates of restoration costs to be incurred in the future and an estimated future inflation rate. Costs estimated are based upon internal and third party calculations and historical experience and future inflation rates are estimated using historical experience and available economic data.
Income taxes
The Company records future tax liabilities to account for the expected future tax consequences of events that have been recorded in its financial statements. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flows and capital expenditures in current and future periods. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded.
TREND ANALYSIS
In 2008, the Company has continued to focus on drilling and completion operations, and anticipates tieing-in multiple wells in the second half of 2008.
The Company’s production for the three months ended June 30, 2008, increased over the prior quarter, as well as the same period of 2007 as a result of new wells coming on production. The average production and revenue realized for the current quarter has exceeded production and revenue of that of any other prior quarters. The Dawson 1-32 well, in which Cinch has a 36% working interest, came on production in mid-April, producing at rates of approximately 10 mmcf/d (gross) for the remainder of the quarter and adding approximately 600 BOE/d (net) to Cinch’s production base.
The Company has made strides on building a stable production base and continues to work on achieving growth. Consistent with other exploration companies, there will be periods of higher production growth, periods of high initial production on new wells which is then anticipated to decline and stabilize in future periods, with some periods experiencing less growth than others.
The Company is significantly affected by commodity price variations. The volatility in oil and gas prices that we have experienced in the past few years directly impacts the revenues and cash flows generated by the Company. In late 2005, the market experienced high commodity prices resulting in increased activity and strong equity valuations. In 2006, we started seeing a softening of the natural gas market and large decreases in prices when compared to the previous year. The decrease in commodity prices impacts the Company by reducing cash flows available for exploration and challenges the economics of potential capital projects. In 2007, the natural gas market continued to soften until the fourth quarter when natural gas prices strengthened while entering the winter months. During the first half of 2008, commodity prices have increased significantly, with natural gas prices at levels that have not been seen since late 2005 and natural gas liquids prices reaching all time highs. An increase in commodity prices results in a direct increase in revenues and cash flows available to fund the Company’s capital program, as well as potentially increase the economics of future projects.
Overall, management believes in the long term strength of the natural gas market, despite short term fluctuations and volatility.
SELECTED ANNUAL AND QUARTERLY INFORMATION
(000's, except per share data)
Q1 Q2 Q3 Q4 Annual
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2008 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and before
royalties 8,137 12,676
Funds from operations 4,130 7,320
Per share - basic 0.07 0.13
- diluted 0.07 0.13
Net income (loss) 17 1,810
Per share - basic 0.00 0.03
- diluted 0.00 0.03
Capital expenditures 8,532 4,584
Total assets 130,566 132,156
Working capital (net debt) (1) (29,160) (26,424)
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Production (BOE/d) 1,579 1,991
----------------------------------------------------------------------------
2007 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and before
royalties 6,116 5,582 4,405 6,588 22,691
Funds from operations 3,371 2,589 1,605 3,217 10,782
Per share - basic 0.06 0.05 0.03 0.06 0.20
- diluted 0.06 0.05 0.03 0.06 0.20
Net income (loss) (268) (709) (15,184) 466 (15,695)
Per share - basic (0.01) (0.01) (0.27) 0.01 (0.29)
- diluted (0.01) (0.01) (0.27) 0.01 (0.29)
Capital expenditures 6,228 3,930 7,851 2,917 20,926
Total assets 136,520 134,834 125,730 125,682 125,682
Working capital (net debt) (1) (17,264) (18,673) (24,987) (24,758) (24,758)
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Production (BOE/d) 1,354 1,249 1,208 1,549 1,340
----------------------------------------------------------------------------
2006 $ $ $ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales,
net of transportation and before
royalties 5,200 4,692 4,487 5,733 20,112
Funds from operations 2,475 2,406 2,115 2,970 9,966
Per share - basic 0.05 0.05 0.05 0.06 0.21
- diluted 0.05 0.05 0.04 0.06 0.20
Net income (131) 879 (576) (488) (317)
Per share - basic (0.00) 0.02 (0.01) (0.01) (0.01)
- diluted (0.00) 0.02 (0.01) (0.01) (0.01)
Capital expenditures 6,696 13,542 7,403 9,324 36,966
Total assets 113,356 121,861 125,894 136,983 136,983
Working capital (net debt) (1) (820) (11,942) (17,307) (23,745) (23,745)
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Production (BOE/d) 1,130 1,141 1,135 1,320 1,182
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Note: numbers may not cross-add due to rounding
(1) Working capital (net debt) excludes the long term financial liabilities
which consists of the long term portion of the capital lease obligation
(June 30, 2008 - $0, December 31, 2007 -- $0, December 31, 2006 --
$276,806).
Financial Statements
Cinch Energy Corp.
June 30, 2008
(unaudited)
CINCH ENERGY CORP.
BALANCE SHEETS
(unaudited)
June 30, December 31,
2008 2007
As at $ $
----------------------------------------------------------------------------
ASSETS (notes 4 and 5)
Current
Accounts receivable 5,958,918 4,150,650
Prepaid expenses and deposits 994,295 859,335
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6,953,213 5,009,985
Property, plant and equipment (note 3) 125,203,224 120,672,360
----------------------------------------------------------------------------
132,156,437 125,682,345
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LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities 11,565,666 8,894,185
Credit facility (note 4) 21,669,228 20,589,362
Current portion of capital lease obligation
(note 5) 142,056 284,112
----------------------------------------------------------------------------
33,376,950 29,767,659
Asset retirement obligations (note 6) 3,446,484 3,448,714
Future income taxes (note 7) 10,400,700 7,150,800
----------------------------------------------------------------------------
47,224,134 40,367,173
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Commitments (notes 9 and 10)
Shareholders' equity
Share capital (note 9) 96,649,434 99,175,434
Contributed surplus (note 9) 3,362,590 3,046,632
Deficit (15,079,721) (16,906,894)
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84,932,303 85,315,172
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132,156,437 125,682,345
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See accompanying notes
CINCH ENERGY CORP.
STATEMENTS OF OPERATIONS, COMPREHENZIVE INCOME (LOSS) AND DEFICIT
(unaudited)
--------------------------------------------------
For more information, please contact
Cinch Energy Corp.
John W. Elick
Chief Executive Officer
(403) 693-0090
Email: [email protected]
or
Cinch Energy Corp.
George Ongyerth
President
(403) 693-0090
Email: [email protected]
Website: www.cinchenergy.comMajor Newsire & Press Release Distribution with Basic Starting at only $19 and Complete OTCBB / Financial Distribution only $89
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