Connacher Oil and Gas Reports Solid Third Quarter 2011 Results; Bitumen Production Doubles; Downstream Contribution Significant; Strong Liquidity and Earnings

CALGARY, Nov. 10, 2011 /CNW/ - Connacher Oil and Gas Limited is pleased to report solid operating and financial results for the third quarter ("Q3 2011") and for the nine months ("YTD 2011") ended September 30, 2011. Connacher also reported on its strengthening liquidity position and updated its 2011 production guidance. Connacher expects its solid performance to continue in Q4 2011.

"During the third quarter of 2011, we made significant progress from an operational, technology and liquidity perspective," said Richard Gusella, Chairman and Chief Executive Officer. "In addition to planned asset sales, we advanced toward farmouts and a joint venture that, upon completion, should provide the benefits of third-party spending on our properties and lower capital spending by Connacher, while we meet 2012 financial obligations without any equity dilution and with reduced indebtedness."

Highlights for Q3 2011 are as follows:

  • Bitumen production doubled over Q3 2010, reflecting the impact of Algar

  • Adjusted EBITDA rose 46 percent to $37.3 million from $25.6 million last year

  • Cash flow at $15.8 million increased 10 percent over last year, despite a 4 percent decline in realized bitumen prices

  • Sold Halfway Creek property for $26.8 million; made progress on Latornell sale

  • Cash position at September 30, 2011 was a healthy $81.7 million, up 60 percent from $51.1 million a year earlier

  • Refinery results were strong, with netbacks up 29 percent to $17.9 million, for a 14 percent margin, confirming the validity of an integrated strategy with a heavy oil production base

  • Oil sands joint venture process initiated and progressing favourably, with strong interest as anticipated; process for conventional central Alberta assets to be undertaken

  • SAGD+TM technology delivered breakthrough results

  • Earnings buoyed by effective hedging, which more than offset impact of a weak Canadian dollar YTD 2011; added more hedging to protect against a possible 2012 economic downturn.

Great Divide: Bitumen production growth, SAGD+™ breakthrough and JV update

Our Great Divide bitumen production averaged 13,454 bbl/d in the third quarter of 2011, up approximately 100 percent from 6,758 bbl/d a year earlier, due to the addition of our Algar operation. We continue to have surplus steam at Algar, which will be utilized as the reservoir signals its receptivity, which should further enhance overall productivity within the rampup process. We also expect to transition to low pressure steam-assisted gravity drainage ("SAGD") at Algar during the latter part of this year or into 2012, which should further lower our steam:oil ratio ("SOR") at that project and overall. During Q3 2011, our SOR at Great Divide was 4.1, reflecting the continuing rampup at Algar and the impact of a turnaround at Pod One in September 2011. SORs were also adversely influenced by the impact of underperforming wells on Pod One's north pad.  Over time, we anticipate redirecting related steam volumes to new, better-situated well pairs which we envisage will result in project SORs at considerably lower levels.  This initiative will be deferred at least until joint venture/sell down discussions are concluded.

There is also potential for further productivity gains through the application of our SAGD+™ steam and solvent technology, which demonstrated very favourable and what we consider to be breakthrough results during a Q3 2011 field trial at two wells on Pad 203 at Algar. Beyond boosting production and lowering our SOR, our field trial achieved a solvent recovery rate that we believe is high enough to be economic in production scenarios and to our knowledge is higher than any other bitumen producer has achieved in field trial testing. Given the cost of solvent, a high recovery rate is crucial for project economics.

It is anticipated that our field trial will continue on two new wells for the duration of this year, after which results will be evaluated. A determination will be made on its broadened application and commercialization, after our studies of results and related matters, including facility sizing and costs, are completed. As we are in a joint venture process which could involve a sell down of existing projects and financing of the Algar expansion and as we are also awaiting receipt of various regulatory approvals anticipated later this year or in early 2012, it makes sense to determine the scope and extent of SAGD+™ applicability once this process is finalized. This in no way diminishes the importance of the steam with solvent process we have developed, but rather reflects prudent commercial decision-making for the right reasons.

Our Great Divide oil sands joint venture initiative is proceeding as planned. We expect receipt of bids later this year. The transaction could involve an upfront cash payment related to a sell down of a minority interest in our Great Divide projects. Any cash proceeds would be used to further enhance corporate liquidity and reduce long-term debt. Additionally, we anticipate substantial capital commitments to finance the Algar expansion project will be secured, with little or no cash cost to Connacher. The third party capital would be used to complete the staged addition of a further 24,000 bbl/d of productive capacity, bringing total productive capacity at Great Divide to 44,000 bbl/d of bitumen.

Conventional properties: Update on production, planned farmouts and asset sales

Our conventional crude oil production and natural gas production both declined in the third quarter of 2011, compared with a year earlier, due to timely sales of Battrum crude oil production in February 2011 and our Marten Creek natural gas production in April 2011. A portion of the cash proceeds was reallocated and used to finance our conventional programs at Twining and Penhold in central Alberta. This was a simple, quick and effective way to position ourselves for healthy short-run returns and provided a profitable balance to our longer term oil sands development activity.

We continue to advance our light gravity crude oil resource plays in central Alberta and believe we have identified substantial reserve and resource potential.  As announced on November 7, 2011, our independent evaluators, GLJ Petroleum Consultants Ltd. of Calgary, Alberta, in a report dated November 2, 2011, with an effective date of September 30, 2011 have assigned considerable discounted present worth to our Pekisko reserves and separately, to our contingent resources at Twining, Alberta. Also, we have engaged an exclusive financial advisor to assist us in securing either a cash, carry and commitment farmout of most of our central Alberta light gravity crude oil projects or alternatively an outright sale thereof.   We believe this process, which will be conducted with a short time fuse, will have further positive implications for our liquidity and value realization strategy.

We are also nearing completion of a process to sell our extensive landholdings and minor natural gas production at Latornell in the Deep Basin of northwestern Alberta. We anticipate that the transactions should be completed during Q4 2011. Notwithstanding this proposed divestiture, we believe Connacher benefits from having a conventional oil and gas business, in part because of our proven ability to create value quickly from conventional producing properties. They also generally do not require the high level of upfront capital typical of SAGD operations, as production and cash flow are achieved sooner and are thus available to finance growth. Conventional initiatives also represent a balance to oil sands from a regulatory perspective. Oil sands initiatives are usually subject to lengthy regulatory process, but conventional properties are subject to less regulation and can provide growth, while we await regulatory approvals for our oil sands projects.

Update on other assets sold or proposed for sale

During the third quarter of 2011, we closed the sale of our 50 percent interest in the Halfway Creek non-producing oil sands property for $26.8 million, at a considerable profit. We also own and intend to monetize a marketable share position in TSX-listed Gran Tierra Energy Inc., a company which has considerable market value and affords good trading liquidity. As at November 10, 2011, our holding had a market value exceeding $20 million.

Refining continues above rated capacity

Montana Refining sales of refined products averaged 12,820 bbl/d during the third quarter of 2011, consistent with 12,773 bbl/d a year earlier. The refinery continues to operate at or above its rated capacity and generate strong financial results. Based on early indications for Q4 2011, the trend is continuing. This performance is attributable to a period of widened differentials, strong product demand and good weather conducive to extensive paving activity in the refinery's market area, which contributes to strong asphalt demand.

In addition to the significant net operating income being delivered, our ownership in the refinery continues to prove its strategic value. It provides us with a hedge against heavy crude oil differential risk, diluent needed for our oil sands operations and affords us a beneficial window on marketing opportunities in the United States for our bitumen and dilbit.

Financial results

Revenue, net of royalties, totalled $232.8 million in Q3 of 2011, up 47 percent from $158.7 million a year earlier. The gain reflected our significant increase in bitumen production as well as better prices for refined products, partially offset by lower realized bitumen prices and lower production for conventional crude oil and natural gas due to the aforementioned sales.

Net income was $3.6 million or $0.01 per share in Q3 2011, compared with $4.2 million or $0.01 per share a year earlier. In the latest quarter, net income benefited from the effectiveness of our hedging program.

Connacher's improved operational performance in the third quarter of 2011 resulted in higher reported cash flows and higher adjusted EBITDA compared with a year earlier. Cash flow was $15.8 million in Q3 2011, up 10 percent from $14.4 million a year earlier. Adjusted EBIDTA was $37.3 million in Q3 2011, up 46 percent from $25.6 million a year earlier.

Capital spending and liquidity update

Our cash balance rose to $81.7 million at September 30, 2011, up 60 percent from $51.1 million a year earlier and up 319 percent from $19.5 million at December 31, 2010. This reflects a substantial improvement in our liquidity and we anticipate this will continue throughout the balance of 2011. Increases in debt amounts in the quarter as recorded on our balance sheet relate entirely to adjustments for currency movements which impact on USD denominated debt, as we report in Canadian dollars.

We have completed our major outlays for 2011 and do not presently intend to proceed with further significant sustaining or growth expenditures of our own capital on our oil sands properties, as we are awaiting requisite regulatory approvals and also the completion of our joint venture process at Great Divide.

We have lowered our anticipated capital outlays for full year 2011 to an estimated $157 million, which is approximately $5 million less than our prior guidance of $162 million in the second quarter 2011 report. We anticipate an increasing alignment of outlays to cash flow as our operations mature and grow. This should serve to further strengthen our financial capacity and outlook.

Our current cash balances and the proceeds from additional asset sales are earmarked for our debt reduction program, which includes repayment of the $100 million convertible debentures when due in June 2012.  Other than to secure $2 million for letters of credit, our $100 million credit facility remains undrawn and, in the absence of any new unforeseen development, we do not anticipate  undertaking any additional long term borrowings or issuing any additional equity or equity-linked instruments in the foreseeable future.

Revised 2011 production guidance

As previously indicated, our conventional drilling program is now completed for 2011; several indicated crude oil wells remain to be tied in to facilities and further conventional outlays will be held to a minimum thereafter. The completion  of these wells has been delayed by events beyond our control, including the unavailability of  equipment and services on a timely basis and wet weather conditions, which precluded a faster startup of our program earlier in the year.

As a result of these delays and due to the pending sale of our Latornell producing area, which we anticipate in Q4 2011, we have revised our full-year 2011 total upstream production guidance to a range of 14,150 boe/d to 15,750 boe/d, down 1% to 2% compared with the range of 14,300 boe/d to 16,100 boe/d provided in the second quarter of 2011. The change only affects conventional production for reasons cited above. Details are provided in the table below.

2011 revised production guidance  
Bitumen Production (bbl/d) 13,000 - 14,500
Conventional Production (boe/d) (1) 1,150 - 1,250
Total Upstream Production (boe/d) 14,150 - 15,750
(1)  Excludes production from Battrum and Marten Creek/Randall properties from the respective closing
dates of the sale of such properties and adjusted for the anticipated sale of Latornell, subject to
closing. Actual production could differ materially from these estimates-see Forward Looking Information.

Pending the resolution of our joint venture processes currently underway for our oil sands and certain conventional properties, we will not presently provide 2012 production guidance, as there may be a working interest reduction associated with both undertakings.

2012 capital budget

As indicated in our Management's Discussion and Analysis ("MD&A"), our capital budget for 2012 has been constrained to essential maintenance expenditures in the order of $37 million. This spending budget will likely be revisited in early 2012 and could be scaled upward, based on the results of our liquidity measures and in response to evidence of improved oil price realizations. As a result, actual capital expenditures incurred during 2012 could differ materially from these estimates.

2012 capital budget on a cash basis                                       ($ in millions)
Maintenance capital                                      
  Oil sands                                     $20
  Conventional                                     5
  Refining                                     4
  Corporate                                     5
Maintenance                                     34
  Refining                                     3
Total 2012 capital budget on cash basis                                     $37


Our operations continue to perform well and generate substantial adjusted EBITDA and cash flow. Great Divide bitumen production is growing on a year over year basis and is stable on a sequential quarterly basis. Our revenues are supported by hedges through the remainder of this year and into 2012 that provide considerable downside protection in the event oil prices deteriorate. In response to recent market conditions, including an improvement in product margins and crude oil prices, we have expanded and diversified our hedges as detailed in our reporting documents.

Because we are mindful of the importance of exhibiting a high level of liquidity, we are progressing with asset sales, farmouts, joint ventures and the curtailment of capital spending. We anticipate seeing the benefit of third party spending on our properties in 2012 and we will most likely revisit our own 2012 capital spending plans, after we know the outcome of our various liquidity initiatives.

Summary financial and operational results (1)

FINANCIAL ($000 except per share amounts) Q3 2011 Q2 2011 % Q3 2010 % YTD 2011 YTD 2010 %
Revenue, net of royalties $232,806 $234,556 (1) $158,714 47 $646,352 $412,686 57
Adjusted EBITDA (2) $37,323 $37,608 (1) $25,642 46 $90,776 $60,255 51
Cash flow (2) $15,770 $15,873 (1) $14,354 10 $25,873 $26,830 (4)
      Per share, basic and diluted (2) $0.04 $0.04 - $0.03 33 $0.06 $0.06 -
Net earnings (loss) $3,642 $(44,169) 108 $4,159 (12) $(54,628) $(19,053) 187
      Per share, basic and diluted $0.01 $(0.10) 110 $0.01 - $(0.12) $(0.04) 200
Capital expenditures $46,940 $38,988 20 $49,842 (6) $126,758 $227,430 (44)
Cash on hand $81,744 $31,525 159 $51,120 60 $81,744 $51,120 60
Working capital $50,801 $18,954 168 $62,047 (18) $50,801 $62,047 (18)
Long-term debt $865,540 $829,310 4 $873,032 (1) $865,540 $873,032 (1)
Shareholders' equity $477,358 $467,057 2 $530,251 (10) $477,358 $530,251 (10)
OPERATIONAL Q3 2011 Q2 2011 % Q3 2010 % YTD 2011 YTD 2010 %
Daily production volumes (3)                
  Bitumen (bbl/d) 13,454 13,720 (2) 6,758 99 13,459 6,635 103
  Crude oil (bbl/d) 355 398 (11) 819 (57) 430   887 (52)
  Natural gas (Mcf/d) 3,036 3,755 (19) 9,158 (67) 4,518 9,364 (52)
  Barrels of oil equivalent (boe/d) (4) 14,315 14,744 (3) 9,103 57 14,642 9,083 61
Upstream pricing (5)                
  Bitumen ($/bbl) 40.98 $54.49 (25) $42.68 (4) $45.75 $46.02 (1)
  Crude oil ($/bbl) 80.63 $90.93 (11) $62.45 29 $80.11 $65.27 23
  Natural gas ($/Mcf) 4.09 $3.94 4 $3.42 20 $3.79 $4.03 (6)
  Barrels of oil equivalent ($/boe) (4) 41.39 $54.15 (24) $40.74 2 $45.58 $44.15 3
  Throughput - Crude charged (bbl/d) 9,638 9,860 (2) 9,903 (3) 9,753 9,543 2
  Refinery utilization (%) 101 104 (3) 104 (3) 103 101 2
  Margins (%) 14 10 40 13 8 11 8 38
(1)      Effective October 1, 2010, the capitalized costs relating to the company's second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and internal operating expenses net of revenue, were capitalized. Accordingly, the above table does not include production and sales volumes for Algar prior to October 1, 2010
(2)    A non-GAAP measure which is defined below
(3)      Represents bitumen, crude oil and natural gas produced in the period. Actual sales volumes may be different due to inventory changes during the period. Actual volumes sold were 14,331 boe/d in Q3 2011, 14,340 boe/d in Q2 2011 and 14,466 boe/d in YTD 2011 (Q3 2010 - 9,103 boe/d and YTD 2010 - 9,083 boe/d)
(4)      All references to barrels of oil equivalent (boe) are calculated on the basis of 6 Mcf: 1 bbl. This conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation
(5)   Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes

Conference call

These results will be the subject of a Conference Call at 8:00 AM MT on November 11, 2011. To listen to or participate in the live conference call please dial either 1-647-427-7450 or 1-888-231-8191. A replay of the event will be available from Friday, November 11, 2011 at 12:00 MT until 21:59 MT on Friday, November 18, 2011. To listen to the replay please dial either 1-416-849-0833 or Toll Free at 1-855-859-2056 and enter the pass code 20333458. You can also listen to the conference call online, through the following webcast link:

Also, please note that because of the increasing volume of information required to be provided in interim reports, concurrently with the issuance of this press release we are posting our results including our interim report, our MD&A and financial statements on SEDAR and on our website, so additional detail will be immediately available to financial markets and our shareholders.  Click on Investor Info/Financials to access the aforementioned material on our website and we understand public access to Sedar will be available 24 hours after filing, unless you are a subscriber thereto, in which case such material will be immediately available.

About Connacher Oil and Gas Limited

Connacher Oil and Gas Limited is a Calgary-based energy company.  Its primary asset is its 100 percent ownership of bitumen reserves and production from two SAGD plants, Pod One and Algar, at its Great Divide oil sands lease block in northeastern Alberta.  Connacher also owns conventional reserves and production in central Alberta and owns and operates a profitable 9,500 bbl/d heavy crude oil refinery in Great Falls, Montana.

Forward‐Looking Information

This press release contains forward‐looking information including but not limited to, anticipated future operating and financial results, expectations of future production, anticipated capital expenditures for 2011 and 2012 and expectations of revisiting 2012 capital spending plans in the future, anticipated sources of funding for capital expenditures and current and future financial obligations, future liquidity, current expectations of not undertaking any additional long term borrowings and issuing any additional equity or equity-linked instruments in the foreseeable future, future development and exploration activities, the utilization of surplus steam at Algar and the impact thereof on SORs and productivity, the anticipated transition to low pressure SAGD at Algar and the expected impacts thereof on SORs, the anticipated impact of technical innovations on productivity and SORs and possible expansion of the application of SAGD+™ on additional well pairs, future possible joint venture, farmout and sale arrangements and the anticipated impact thereof on the company, timing of receipt of regulatory approvals for future expansion of oil sands properties, reserve and resource potential associated with the company's light gravity resource plays, the proposed sale of Connacher's interest at Latornell, monetization of the company's interest in Gran Tierra Energy Inc.,  the future repayment of Connacher's Convertible Debentures and further rationalization activity and the use of proceeds therefrom.

Forward‐looking information is based on management's expectations regarding future growth, results of operations, production, future commodity prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and results of drilling activity, environmental matters, business prospects and opportunities and future economic conditions. Forward‐looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to operational risks in development, exploration, production and start‐up activities; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks; the risk of commodity price and foreign exchange rate fluctuations; risks associated with the impact of general economic conditions; sales volumes and risks and uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of the Great Divide oil sands project.

The 2011 production guidance contained in this press release is based on certain assumptions regarding operational performance including, among others, steam generation levels and SORs, unplanned operational upsets, well productivity, realized netbacks which may accelerate or delay our capital divestment program and future market conditions and is subject to risks and uncertainties, including those risks and uncertainties described above. Additional risks and uncertainties are described in further detail in Connacher's Annual Information Form ("AIF") for the year ended December 31, 2010 which is available at

Although Connacher believes that the expectations in such forward‐looking information are reasonable, there can be no assurance that such expectations shall prove to be correct. The forward‐looking information included in this press release is expressly qualified in its entirety by this cautionary statement. The forward‐looking information included in this press release is made as of November 10, 2011 and Connacher assumes no obligation to update or revise any forward‐looking information to reflect new events or circumstances, except as required by law.

In addition, design capacity is not necessarily indicative of the stabilized production levels that may ultimately be achieved at Connacher's SAGD facilities. Moreover, reported average or instantaneous production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this press release due to, among other factors, difficulties or interruptions encountered during the production of bitumen or other hydrocarbons.

Per barrel of oil equivalent (boe) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil (6:1). The conversion is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation.

Non‐GAAP Measurements

This press release contains terms commonly used in the oil and gas industry, such as cash flow, cash flow per share, refinery margin,  netbacks and adjusted earnings before interest, taxes, depreciation and amortization ("adjusted EBITDA"). These terms are not defined by the financial measures used by Connacher to prepare its financial statements and are referred to herein as non‐GAAP measures. These non‐GAAP measures should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings (loss) as determined in accordance with Canadian GAAP as an indicator of Connacher's performance. Management believes that in addition to net earnings (loss), cash flow, netbacks, refinery margin and adjusted EBITDA are useful financial measurements which assist in demonstrating the company's ability to fund capital expenditures necessary for future growth or to repay debt. Connacher's determination of cash flow, netbacks, refinery margin and adjusted EBITDA may not be comparable to that reported by other companies.

Cash Flow

Cash flow and cash flow per share do not have standardized meanings prescribed by Canadian GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flows from operating activities and is calculated before changes in non‐cash working capital, pension funding and decommissioning liabilities settled. The most comparable measure calculated in accordance with Canadian GAAP is cash flow from operating activities. Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding. Management uses this non‐GAAP measurement (which is a common industry parameter) for its own performance measure and to provide its shareholders and investors with a measurement of the company's efficiency and its ability to fund future growth expenditures.


Upstream netbacks, including by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from upstream revenues. Downstream netbacks are calculated by deducting crude oil purchases and operating and transportation costs from refining sales revenues.

Adjusted EBITDA

Adjusted EBITDA is calculated as net earnings (loss) before finance charges, current and deferred income tax provisions and recoveries, depletion, depreciation and amortization, exploration and evaluation expense, share‐based compensation, foreign exchange gains/losses, unrealized gains/losses on risk management contracts, interest and other income, gain (loss) on disposition of assets, defined benefit plan expense, share of interest in and loss on associate and costs of refinancing long‐term debt.

Reconciliations of Non‐GAAP Measures

Cash flow is reconciled to cash flow from operating activities and upstream and downstream netbacks and adjusted EBITDA are reconciled to net earnings (loss) in the company's MD&A for the three months and nine months ended September 30, 2011 and 2010.



SOURCE Connacher Oil and Gas Limited

For further information:

Richard A. Gusella
Chairman and Chief Executive Officer


Peter D. Sametz
President and Chief Operating Officer


Grant D. Ukrainetz
Vice President, Corporate Development

Phone:  (403) 538-6201      
Fax:  (403) 538-6225


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