Cinch Energy Corp. Releases Third Quarter 2008 Results

CALGARY, ALBERTA, Nov 7, 2008 (Marketwire via COMTEX) -- CNH | Quote | Chart | News | PowerRating -- Cinch Energy Corp. ("Cinch" or "Company") (TSX:CNH) is pleased to report on the Company's activities and financial results for the third quarter of 2008. Highlights are as follows:

---------------------------------------------------------------------------- Three Months Ended Nine Months Ended September 30, September 30, 2008 2007 2008 2007 ---------------------------------------------------------------------------- (Unaudited) (Unaudited) (Unaudited) (Unaudited) Petroleum and natural gas sales, net of transportation ($000's) 10,132 4,405 30,945 16,103 Sales volumes per day Natural gas (Mcf/d) 10,811 6,050 9,675 6,329 Natural gas liquids (Bbl/d) 247 200 261 215 Equivalence at 6:1 (BOE/d) 2,049 1,208 1,874 1,270 Sales Price Natural gas ($/Mcf) 7.97 5.56 9.11 7.15 Natural gas liquids ($/Bbl) 96.87 71.25 94.94 64.10 Equivalence at 6:1 ($/BOE) 53.75 39.63 60.28 46.45 $ $ $ $ Funds from operations (000's) (1) 5,635 1,605 17,085 7,565 - per share, basic (1) 0.10 0.03 0.31 0.14 - per share, diluted (1) 0.10 0.03 0.31 0.14 Net income (loss) (000's)(3) 774 (15,184) 2,602 (16,161) - per share, basic 0.01 (0.27) 0.05 (0.30) - per share, diluted 0.01 (0.27) 0.05 (0.30) Capital expenditures ($000's) 12,212 7,851 25,329 18,009 Basic weighted average shares outstanding (000's) 55,628 55,625 55,626 54,101 Working capital (net debt)(2) ($000's) - As at September 30, 2008 (32,994) - As at December 31, 2007 (24,758) As at November 6, 2008 Common shares outstanding 55,631,798 Options outstanding 4,696,500 - Weighted average exercise price 1.65 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- (1) Funds from operations and funds from operations per share is not a generally accepted accounting principle ("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. (3) Net loss for the three and nine months ended September 30, 2007 includes a goodwill writedown of $14,616,996.

President's Message

PRODUCTION, PRICES, AND COSTS

Production for the three months ended September 30, 2008 averaged 2,049 BOE/d versus an average of 1,208 BOE/d, a 70% increase over the third quarter of 2007. The third quarter average production rate of 2,049 BOE/d is a 58 BOE/d increase over the 1,991 BOE/d second quarter production rate, and is the fourth consecutive quarter of increased production for the Company. The third quarter production increase would have been greater had the two Kiskatinaw wells on the Dawson property commenced production on schedule in September as previously anticipated, but surface land issues in the Dawson area, along with expansions of existing production facilities, have delayed projected on stream dates for the Company's new production adds. The Dawson 12-27 and Dawson 13-11 wells commenced production near the end of October increasing Cinch's current production to approximately 2,550 BOE/d. Cinch remains on track to achieve its projected average 2008 production rate of 1,900 - 2,100 BOE/d. The Dawson 6-6 Wabamun well, projected to add approximately 700 BOE/d to Cinch's production base, is expected to commence production in the first quarter of 2009. The Company continues to grow its production volumes in British Columbia and the Dawson area will continue to be a focus of future capital expenditures.

Commodity prices for the third quarter of 2008 decreased significantly from the second quarter, from $69.97 per BOE to $53.75 per BOE. This decrease is due primarily to a drop in natural gas prices from $10.74 per mcf to $7.97 per mcf. Natural gas liquids decreased from $104.46 per barrel to $96.87 per barrel. Most recently with the financial turmoil that the markets are experiencing the price of oil has also fallen sharply from in excess of $100 per barrel to approximately $65 per barrel. The current market uncertainties make it difficult to predict what commodity prices will be in the near future. The Company does not have any hedges in place and maintains its balance sheet through rigorous control of its capital expenditures.

Operating costs in the third quarter of 2008 were $5.99 per BOE as compared to $6.24 per BOE in the second quarter, primarily due to an increase in production in the Dawson area which has lower operating costs. Operating expenses per BOE are expected to decrease again in the fourth quarter of 2008 and are anticipated to average approximately $5.75 per BOE for 2008 due to an increase in production volumes from the Dawson area.

OPERATIONS

During the third quarter of 2008, Cinch participated in the drilling of 4 wells, all of which were cased as gas wells. Subsequent to the third quarter end, one well was cased as a potential gas well and two wells were drilling at the time of this report.

At Dawson, B.C., the Dawson 6-6 well (85% working interest) was deepened to evaluate a Wabamun prospect. This well was completed and flowed over a four day period at a stable rate of 6.4 mmcf/d of very dry gas. Cinch farmed in on its area partner and paid the deepening and completion costs of this well in order to earn an 85% working interest in the well below the Kiskatinaw formation and an additional 4 sections of land surrounding the well. Cinch has identified multiple prospective locations and spudded a second deep test well located at Dawson 14-26 in late October. This well is projected to reach total depth some time in December. In addition, the Company participated for 40% in the drilling of Dawson 6-1, which has been cased as a potential gas well. Currently, the Dawson 10-15 well (40% interest) is drilling and will reach total depth in November. The Company has also expanded its land holdings in the mineral rights below the Montney horizon by acquiring interests in 10 sections of land (50%-85% working interest) at B.C. land sales and through a private transaction. Currently, the Company holds mineral rights in 51 sections of land in the Dawson area.

At Chime, the Company has participated in the drilling of the Chime 14-6 location (40% working interest) which has been completed as a gas well and commenced production in August.

In the Kakwa E pool, Cinch has drilled and completed two gas wells located at Kakwa 3-12 (45% working interest) and Kakwa 11-7 (49.4% working interest). These wells complete the three well Dunvegan development program commenced in June and are currently producing at 300 BOE/d net to the Company.

FINANCIAL

Subsequent to the end of the third quarter, the Company expanded its line of credit from $34 million to $40 million. This credit facility increase will provide additional flexibility in developing and expanding the Dawson property. The Company announced in September that its capital program was expanded from $25 million to $36 million, however under the current market conditions and falling commodity prices it is anticipated that capital expenditures will be reduced to $33 million for 2008. The Company is developing its capital program for 2009, however the intent is to continue to be extremely disciplined with the majority of future expenditures destined for the Dawson area of British Columbia.

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, timing and commencement of production for new wells, production estimates, budgeted capital expenditures and the method of funding thereof, anticipated production rates, timing of completion and tie-in of wells, expected royalty rates and changes to the Alberta royalty regime and the possible effect thereof on the Company and its allocation of capital, expected 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. 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

November 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 nine month periods ended September 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

The Company's production for the third quarter of 2008 was approximately 2,049 BOE/d, an increase from the second quarter production of 1,991 BOE/d. The increase in production can be attributed to 4 new wells which came on production in late August and mid to late September in the Chime and Kakwa areas at combined rates of approximately 1.8 mmcf/d (net) to Cinch's production. It is anticipated that the new wells will experience typical Deep Basin decline rates in their first year of production.

For the three months ended September 30, 2008, the Company incurred $12.2 million of capital expenditures exiting the quarter with net debt of $33.0 million, $27.5 million of which is drawn on its $34 million demand bank credit facility. Subsequent to September 30, 2008, the Company increased its revolving, demand bank credit facility to $40 million. The increase in the credit facility along with cash flows generated will provide increased access to capital for the Company's 2008/2009 drilling programs.

In the fourth quarter of 2008, the Company plans to drill, complete and tie-in multiple locations primarily in the Dawson area. In the last week of October, the Company tied in two new wells in the Dawson area resulting in additional production of approximately 400 BOE/d (net), increasing current production to approximately 2,550 BOE/d.

PRODUCTION ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- Sales volumes % % Natural gas (mcf/d) 10,811 6,050 79 9,675 6,329 53 Liquids (bbl/d) 247 200 24 261 215 22 Equivalence (BOE/d) 2,049 1,208 70 1,874 1,270 48 Sales prices $ $ % $ $ % Natural gas 7.97 5.56 43 9.11 7.15 27 Liquids 96.87 71.25 36 94.94 64.10 48 Equivalence 53.75 39.63 36 60.28 46.45 29 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Sales volumes for the three and nine months ended September 30, 2008, increased over the same periods of 2007 due to eleven additional wells brought on production since September 2007.

Natural gas prices were 43% and 27% higher for the three and nine months ended September 30, 2008, respectively, compared to the same periods of 2007. Natural gas prices for the three months ended September 30, 2008 were 26% lower than the second quarter of 2008 and remained weak subsequent to the quarter end. The Company's natural gas production continues to be unhedged and is marketed in the Alberta spot market.

Natural gas liquids pricing was 36% and 48% higher for the three and nine months ended September 30, 2008, respectively, compared to the same periods of 2007. 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 ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Petroleum and natural gas sales, net of transportation 10,132 4,405 130 30,945 16,103 92 Per BOE 53.75 39.63 36 60.28 46.45 30 ----------------------------------------------------------------------------

Revenues for the three and nine months ended September 30, 2008 were 130% and 92% higher, respectively, than the same periods of 2007 due to higher production, as well as higher commodity prices. Transportation expense per BOE for the first nine months of 2008 was consistent with 2007.

Revenues for the three months ended September 30, 2008 have decreased from the second quarter of 2008, as a result of lower natural gas prices partially offset by higher production.

ROYALTIES Dollars in thousands, except per unit amounts ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Royalties 2,434 1,111 119 7,782 3,508 122 Per BOE 12.91 10.00 29 15.16 10.12 50 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Royalty expense increased in the three and nine months ended September 30, 2008 compared to the same periods of 2007 primarily due to higher revenues, as well as expiration of royalty holidays on some higher producing wells.

Royalty expense for the third quarter of 2008 decreased over the second quarter of 2008 consistent with the lower revenues generated. The royalty rate (royalties as a percentage of oil and gas sales) for the third quarter of 2008 is 2% lower than the second quarter at approximately 24%. This can be attributed to some deep well and summer drilling royalty credits received in the third quarter from drilling activities in British Columbia. This rate is comprised of both crown royalties and gross overriding royalties.

The royalty rate for 2008 is expected to be similar to the rate experienced in the first nine months of 2008. 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 current assessment, Cinch has increased its capital spending in the Dawson Area of British Columbia, where royalty rates are more favorable.

OPERATING EXPENSES Dollars in thousands, except per unit amounts ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Operating 1,130 878 29 3,111 2,347 33 Per BOE 5.99 7.90 (24) 6.06 6.77 (10) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Total operating expenses for three and nine months ended September 30, 2008 were higher than the same periods of 2007 due to increased gas processing fees attributable to higher production, higher operators' overhead costs, as well as an increase in compressor and equipment maintenance costs and higher methanol and treating supplies used. Operating expenses per BOE decreased due to increased production.

Total operating expenses for the third quarter of 2008 were consistent with the second quarter with a decrease in operating expenses per BOE due to increased production.

Operating expenses per BOE are expected to continue to decrease in the fourth quarter of 2008 and are expected to average approximately $5.75 per BOE for the year. Anticipated 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 ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % General and administrative 834 851 (2) 2,683 2,872 (7) Per BOE 4.42 7.66 (42) 5.23 8.28 (37) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Total general and administrative expenses decreased for the three and nine months ended September 30, 2008 compared to the same periods of 2007 due to decreased stock based compensation expense, as well as higher overhead recoveries resulting in a direct reduction of general and administrative expenses, partially offset by higher public company related expenses. The Company does not capitalize indirect general and administrative expenses.

For the three and nine months ended September 30, 2008, general and administrative expenses per BOE were lower 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 in the third quarter by approximately $28 thousand compared to the second quarter due to increased overhead recoveries, partially offset by higher consulting fees.

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 ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Interest expense 263 234 12 833 660 26 Per BOE 1.39 2.11 (34) 1.62 1.90 (15) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Interest expense increased in the three and nine months ended September 30, 2008 compared to the same periods of 2007 due to higher draws on the Company's bank credit facility in 2008, exiting the quarter with an outstanding credit facility balance of $27.5 million on its $34.0 million credit facility. In 2007, the Company exited the third quarter with an amount outstanding under its credit facility of $17.4 million. Subsequent to September 30, 2008, the Company increased its revolving demand bank credit facility to $40 million. The facility bears interest at the lender's prime rate plus one quarter to one half basis points depending on the Company's net debt to funds from operations ratio. The increase in the credit facility will provide increased capital for the Company's 2008/2009 drilling programs.

ACCRETION OF ASSET RETIREMENT OBLIGATIONS EXPENSE Dollars in thousands, except per unit amounts ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Accretion expense 48 46 4 141 132 7 Per BOE 0.26 0.42 (38) 0.28 0.38 (26) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Accretion expense increased in the three and nine months ended September 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 ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Depletion and depreciation 4,385 2,628 67 12,876 9,123 41 Per BOE 23.26 23.64 (2) 25.08 26.32 (5) ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Total depletion and depreciation expense for the three and nine months ended September 30, 2008 increased compared to the same period of 2007 due to increased production, as well as a larger capital asset base being depleted. Depletion per BOE for the three and nine months ended September 30, 2008 decreased compared to the same periods of 2007 due to positive drilling results resulting in reserve additions.

The depletion and depreciation expense in the third quarter of 2008 decreased compared to the second quarter by approximately $289 thousand or $2.54/BOE due to reserve additions added in the third quarter based on an internal reserve assessment.

TAXES Dollars in thousands, except per unit amounts ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Future income taxes (recoveries) 308 (751) 141 1,032 (934) 210 Per BOE 1.64 (6.75) 124 2.01 (2.69) 175 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

A future income tax expense was recorded in the three and nine months ended September 30, 2008 commensurate with the net income experienced during the periods.

Tax pools at September 30: In thousands ---------------------------------------------------------------------------- 2008 2007 $ $ ---------------------------------------------------------------------------- COGPE 15,781 13,531 CDE 27,394 25,227 CEE 24,397 28,470 UCC 17,942 19,485 ---------------------------------------------------------------------------- 85,514 86,713 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

The Company's tax pools decreased since September 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 September 30, 2008, all the required expenditures had been incurred.

NET INCOME (LOSS) AND FUNDS FROM OPERATIONS In thousands, except per share figures ---------------------------------------------------------------------------- Three Months Nine Months Ended September 30, Ended September 30, 2008 2007 Change 2008 2007 Change ---------------------------------------------------------------------------- $ $ % $ $ % Net income (loss) 774 (15,184) 105 2,602 (16,161) 116 per basic share 0.01 (0.27) 105 0.05 (0.30) 116 per diluted share 0.01 (0.27) 105 0.05 (0.30) 116 Funds from operations 5,635 1,605 251 17,085 7,565 126 per basic share 0.10 0.03 233 0.31 0.14 122 per diluted share 0.10 0.03 233 0.31 0.14 122 Weighted average shares outstanding 55,628 55,625 0 55,626 54,101 3 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

For the three and nine months ended September 30, 2008, the Company generated net income attributable to increased production and higher commodity prices compared to the same periods of 2007.

The Company's funds from operations for the three and nine months ended September 30, 2008 increased by 251% and 126%, respectively, over the same periods of 2007. Funds from operations in 2008 are higher due to increased operational efficiencies in conjunction with increased revenues resulting from higher production, as well as higher commodity prices.

LIQUIDITY AND CAPITAL RESOURCES In thousands ---------------------------------------------------------------------------- September 30, 2008 December 31, 2007 Change ---------------------------------------------------------------------------- $ $ % Working capital deficiency 5,471 4,168 31 Credit facility 27,523 20,589 34 ---------------------------------------------------------------------------- Net debt 32,994 24,757 33 Shareholders' equity 85,832 85,315 1 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

At September 30, 2008, the Company had net debt of $33.0 million, comprised of a working capital deficiency of $5.5 million and an amount outstanding on its credit facility of $27.5 million. The $8.2 million increase in net debt from December 31, 2007, can be attributed to capital expenditures of $25.3 million partially offset by funds from operations for the nine months ended September 30, 2008 of $17.1 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 despite the weakness in commodity prices, has forecast that it has sufficient capital to carry out the planned 2008 program. At September 30, 2008, the Company had draws of $27.5 million on its $34.0 million demand bank credit facility. Subsequent to September 30, 2008, the Company increased its revolving demand bank credit facility to $40 million. The facility bears interest at the lender's prime rate plus one quarter to one half basis points depending on the Company's net debt to funds from operations ratio.

The increase in shareholder's equity at September 30, 2008 from December 31, 2007 can mostly be attributed to the net income realized in 2008 partially offset by the tax effect of $10 million in flow-through share expenditures renounced in January 2008 on flow-through shares issued in February 2007.

CAPITAL EXPENDITURES Additions to property, plant and equipment In thousands ---------------------------------------------------------------------------- Nine months ended September 30, 2008 2007 ---------------------------------------------------------------------------- $ $ Land and rentals 3,503 2,118 Seismic 1,698 272 Drilling, completing and equipping 17,142 13,497 Pipelines and facilities 2,694 2,054 Other assets 292 68 ---------------------------------------------------------------------------- Total 25,329 18,009 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

Capital expenditures for the nine months ended September 30, 2008 include approximately $3.3 million relating to land acquisitions in the Dawson and Kakwa areas. At the B.C. land sale on August 13, 2008, and through a private transaction, Cinch was successful in acquiring an additional 10 sections of land (50-85% working interest) prospective for deeper horizons in the Dawson area. The remainder of the capital expenditures was incurred primarily on drilling, completing, as well as tieing-in locations in the Dawson, Kakwa, and Chime areas. At September 30, 2008, based on an internal reserve assessment, additional reserves were added through drilling and completion operations in the Kakwa, Dawson and Chime areas.

The Company has increased its 2008 capital budget from $25 million to approximately $33 million as a result of exploration success in the Dawson area. This additional capital will be allocated to the Dawson area for land acquisitions, drilling activities, acquisitions of 3-D seismic data, as well as expanding the existing production facilities to accommodate additional wells. The Company currently has interests in 51 gross sections (21.5 net sections) of land in the Dawson area and expects to allocate a significant portion of its 2009 capital budget to this active multi-zone area.

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 increased risks to the Company, particularly during periods when access to capital is limited 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 Company also attempts to mitigate risks 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. To date, the Company has not implemented any hedging instruments.

The Company has selected the appropriate personnel to monitor operations and has automated field information where possible, so that operational issues can be assessed and dealt with on a timely basis. The Company, however, is not the operator in all cases and therefore not all operational issues are within its 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 can have an impact on the Company's activity levels and potentially delay operations.

The Government of Alberta will implement its new proposed royalty framework effective January 1, 2009. 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.

On January 24, 2008, the Alberta Government announced its plan to reduce projected emissions in the province by 50% by 2050. This will result in real reductions of 14% below 2005 levels. The Alberta Government stated it would form a government-industry council to determine a go forward plan for implementing technologies, which will significantly reduce greenhouse gas emissions by capturing air emissions from industrial sources and locking them permanently underground in deep rock formations (carbon capture). In addition, the plan calls for energy conservation by individuals and for increased investment in clean energy technologies and incentives for expanding the use of renewable and alternative energy sources such as bioenergy, wind, solar, hydrogen, and geothermal. Initiatives under this theme will account for 18% of Alberta's reductions.

On January 31, 2008, the Government of Canada and the Province of Alberta released the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among others: (i) incorporating carbon capture and storage into Canada's clean air regulations; (ii) allocating new funding into projects through competitive process; and (iii) targeting research to lower the cost of technology.

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 were provided in the Company's Annual Information Form for the year ended December 31, 2007.

Global financial crisis

The current global financial crisis has reduced liquidity in financial markets thereby restricting access to financing and has caused significant volatility to commodity prices. These factors have negatively impacted company valuations and will impact the performance of the global economy going forward. Petroleum prices are expected to remain volatile for the remainder of 2008 and into 2009 as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing global credit and liquidity concerns.

However, in 2008 Cinch has significantly increased cash flows from operations over the prior years and forecasts a further increase in cash flows for 2009 assuming that average commodity prices in 2009 remain comparable to those achieved in 2008 and that production forecasts are also achieved. As well, Cinch has secured an increased revolving demand bank credit facility of $40 million (previously $34 million) that will enhance the Company's ability to manage through these uncertain times.

DISCLOSURE CONTROLS AND PROCEDURES

The Company has designed disclosure controls and procedures to provide reasonable assurance that material information relating to the Company 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 September 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 years 4-5 years greater than 1 year 5 years ---------------------------------------------------------------------------- Operating lease 242 207 35 - - ---------------------------------------------------------------------------- 242 207 35 - - ---------------------------------------------------------------------------- ----------------------------------------------------------------------------

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 nine months ended September 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 drilling and tieing-in multiple wells during the fourth quarter of 2008.

The Company's production for the three months ended September 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 realized for the current quarter has exceeded production of that of any other prior quarters.

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 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 increased significantly, with natural gas prices at levels that had not been seen since late 2005 and natural gas liquids and oil prices reaching all time highs. In the third quarter of 2008, commodity prices once again softened resulting in a decrease in revenues, as well as a decrease of cash flows available to fund the Company's capital program. Subsequent to September 30, 2008 the Company increased its revolving demand bank credit facility from $34 million to $40 million. The increase in the credit facility along with increased forecasted cash flows due to higher forecasted production in the fourth quarter and going into 2009 will provide the Company with increased access to capital for its 2008/2009 drilling program.

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 ---------------------------------------------------------------------------- 2008 $ $ $ $ $ ---------------------------------------------------------------------------- Petroleum and natural gas sales, net of transportation and before royalties 8,137 12,676 10,132 Funds from operations 4,130 7,320 5,635 Per share - basic 0.07 0.13 0.10 - diluted 0.07 0.13 0.10 Net income (loss) 17 1,810 774 Per share - basic 0.00 0.03 0.01 - diluted 0.00 0.03 0.01 Capital expenditures 8,532 4,584 12,212 Total assets 130,566 132,156 142,147 Working capital (net debt) (1) (29,160) (26,424) (32,994) ---------------------------------------------------------------------------- Production (BOE/d) 1,579 1,991 2,049 ---------------------------------------------------------------------------- 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) ---------------------------------------------------------------------------- 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) ---------------------------------------------------------------------------- Production (BOE/d) 1,130 1,141 1,135 1,320 1,182 ---------------------------------------------------------------------------- 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 (September 30, 2008 - $0, December 31, 2007 - $0, December 31, 2006 - $276,806). Financial Statements Cinch Energy Corp. September 30, 2008 (unaudite

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