CALGARY, Nov. 9 /CNW/ - Connacher Oil and Gas Limited (CLL - TSX)
continued to strengthen its overall operating and financial results and
financial condition in the third quarter of 2006. This was achieved through
growth in conventional production, strong refinery operations and timely
equity and debt financing. Meanwhile, Connacher is executing its oil sands
development plans with significant progress on its great divide project. Field
site preparation and construction, shop construction of major equipment and
mechanical and civil design work are all advancing favorably. The first 15
steam-assisted gravity drainage ("SAGD") well pairs are to be drilled in late
2006 and early 2007.
For the third quarter of 2006, Connacher's Montana refinery showed
expanded throughput, improved margins and higher utilization rates. In the
meantime, conventional production in Alberta and Saskatchewan was a steady
3,256 boe/d. The company reported record cash flow from operations of
$15 million for the third quarter compared with $9.5 million for the second
quarter of 2006, and $2 million for the third quarter of 2005. Earnings also
reached record levels at $6.8 million. These strong financial results are
anticipated to continue and be expanded considerably in upcoming years when
production from pod one is initiated and additional pod development and
related production is introduced in a sequential manner during the balance of
the decade.
<<
Highlights for Third Quarter 2006
- Q3 2006 revenue up 3,227 percent to $103 million compared to Q3 2005
levels; nine months 2006 revenue up 2,421 percent to $167 million
- Q3 2006 cash flow of $15 million ($0.08 per share), an increase of 656
percent over 2005; nine months 2006 cash flow at $26.2 million ($0.15
per share), up 739 percent over $3.1 million last year
- Q3 2006 earnings of $6.8 million ($0.03 per share) compared to a loss
in 2005; nine months 2006 earnings of $3.7 million, up 799 percent
- Q3 2006 conventional production up 265 percent to 3,256 boe/d,
compared to 891 boe/d in 2005; nine months 2006 production at
2,626 boe/d, up 194 percent
- Montana refinery performs well with higher throughput, better margins
- GLJ reserve and resource estimates for Great Divide oil sands
properties expanded significantly
- $30 million of new flow through equity and US$195 million of new debt
facilities placed to provide capital for Great Divide and for
refining operations
- Great Divide field construction well underway
Financial & Operating Highlights
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
% %
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
FINANCIAL ($000's except
per share amounts)
Total revenue 103,108 3,222 3,100 167,984 6,818 2,364
Cash flow from
operations before
working capital
changes(1) 14,957 1,978 656 26,184 3,120 739
Per share, basic(1) 0.08 0.02 300 0.15 0.03 400
Per share, diluted(1) 0.08 0.02 300 0.14 0.03 367
Net earnings (loss)
for the period 6,771 (1,034) 755 3,686 410 799
Per share, basic 0.03 (0.01) 400 0.02 - -
Per share, diluted 0.03 (0.01) 400 0.02 - -
Capital expenditures
and acquisitions 41,449 2,870 1,344 376,564 14,567 2,485
Cash on hand 14,450 67,708 (79)
Working capital
(deficit)(2) (39,942) 67,440 (159)
Shareholders' equity 378,730 113,208 235
Total assets 527,028 118,788 344
OPERATING
Conventional daily
sales volumes
Crude oil - bbl/d 1,084 808 34 926 713 30
Natural gas - mcf/d 13,028 497 2,521 10,198 1,077 847
Barrels of oil
equivalent - boe/d(3) 3,256 891 265 2,626 893 194
Conventional selling
prices
Oil - $/bbl 62.53 53.40 17 56.83 42.62 33
Natural gas - $/mcf 5.33 1.88 184 5.58 1.21 361
Barrels of oil
equivalent - $/boe(3) 42.16 49.48 (15) 41.70 35.50 17
Refining(4)
Sales revenue 93,752 - 144,719 - -
Margins 13,510 - 17,373 - -
Margins (%) 14.4 - 12.0 - -
Common shares
outstanding (000's)
Weighted average
Basic 193,587 103,851 86 179,948 96,018 87
Diluted 200,572 106,397 89 187,135 101,073 85
End of period
Issued 197,878 134,236 47
Fully diluted 213,491 142,873 49
-------------------------------------------------------------------------
(1) Cash flow from operations before working capital changes ("cash
flow") and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow includes all cash flow from operating
activities and is calculated before changes in non-cash working
capital. The most comparable measure calculated in accordance with
GAAP would be net earnings. Cash flow is reconciled with net earnings
on the Consolidated Statement of Cash Flows and in the accompanying
Management's Discussion & Analysis. Management uses these non-GAAP
measurements for its own performance measures and to provide its
shareholders and investors with a measurement of the company's
efficiency and its ability to fund a portion of its future growth
expenditures.
(2) A short term working capital deficiency exists at September 30, 2006
as part of the consideration paid for the refinery acquisition which
was financed with short-term borrowings. This short term debt was
repaid in October 2006.
(3) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 mcf:1 bbl. Boes may be misleading, particularly if
used in isolation. 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.
(4) Results from the date of purchase of the refinery on March 31, 2006
to September 30, 2006. In the month of April 2006 the refinery was
shut down for approximately 20 days for scheduled turnaround
maintenance.
>>
Letter to Shareholders
Connacher continued to demonstrate improved financial and operating
results during the third quarter of 2006. By consistently pursuing its
objectives with a well-defined integration strategy, the Company's financial
condition was strengthened, internally generated cash flow from operations
before working capital changes grew significantly and considerable earnings
were achieved. In particular, the Montana refinery was a significant performer
during the reporting period as throughput was expanded, margins were improved
and utilization rates were exceptional. Readers should note that cash flow
from operations before working capital changes ("cash flow" or "cash flow from
operations") and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles ("GAAP"). See
Management's Discussion and Analysis herein.
Considerable effort during the third quarter 2006 was focused on the
continued strengthening of the company's overall financial condition and
capacity to fund its development program at Pod One of the Great Divide oil
sands project. During the summer, $30 million of flow through equity was sold
by way of a bought deal financing to secure funds for the company's ongoing
core hole and 3D seismic evaluation program anticipated for the company's key
Great Divide oil sands leases in the winter of 2007. A total of 70 core holes
and extensive 3D coverage is scheduled for the upcoming winter drilling
season.
Also, subsequent to the reporting period, Connacher completed the private
placement of a US$180 million Term Loan B Facility ("Term Loan") and a
US$15 million Working Capital Facility ("WC Facility") to institutional
investors primarily in the United States. The Term Loan has a seven year term,
nominal scheduled principal repayments and bears interest at either LIBOR plus
3.25 percent or at a Base Rate plus 2.25 percent. Under certain circumstances,
limited additional periodic repayments may be required commencing in 2008. A
portion of the Term Loan proceeds were used to discharge short-term
indebtedness incurred to acquire the refining assets in Montana, to fund a one
year debt service reserve during the construction phase at Pod One of Great
Divide and to pay expenses associated with the financing. The balance of
approximately US$111 million was added to working capital to be available for
the construction project at Pod One.
To reduce risk, an interest rate swap establishing a rate of 8.52 percent
on US$90 million of the Term Loan over its term was also completed.
The WC Facility is fully revolving, has a five year term and bears
interest at either LIBOR plus three per cent or at a Base Rate plus two per
cent. It was secured to provide ongoing working capital for the Montana
refinery operations.
Connacher's Great Divide assets and the Montana refining assets provided
security for the two facilities, which are non-recourse to Connacher. As the
transaction closed after the reporting period cutoff, Connacher's nine-month
balance sheet shows a working capital deficit due to the impact of the bridge
loan incurred to acquire the Montana refining assets. This has since been
redressed, leaving Connacher with a well-structured balance sheet, strong
working capital position and growing cash flow from operations to fund other
growth investment opportunities. As well, the company continues to hold an
extremely valuable unencumbered equity position approaching $300 million in
Petrolifera Petroleum Limited and Connacher has unutilized credit facilities
deriving from the loan value of its conventional assets.
Of particular additional importance during the reporting period was the
completion by GLJ Petroleum Consultants ("GLJ") of an updated report on the
reserves and resources at the company's Great Divide oil sands project,
situated approximately 80 kilometers (50 miles) southwest of Fort McMurray in
northeastern Alberta. Connacher owns a 100 percent working interest in most of
its 80,000 acre lease holding in the region, including Pod One which is
presently under development. Clearly the company's oil sands properties are of
considerable consequence to the value of Connacher and remain its most
significant asset.
The following is a summary of the bitumen reserves and the value of
future net revenues associated with Connacher's interests in the Great Divide
region, as evaluated by GLJ as of September 1, 2006. The GLJ Report was
prepared using assumptions and methodology guidelines outlined in the COGE
Handbook and in accordance with National Instrument 51-101. The pricing used
in the forecast and constant price evaluations is set forth in the notes to
the tables.
Reserves were only assigned to Pod One, in the 2P and 3P categories,
although no proved reserves were assigned pending start-up of production. The
study assumed 59 SAGD well pairs for the 2P case and 80 well pairs for the 3P
case, with cumulative Steam Oil Ratios ("SORs") of 2.6 in both cases, but
declining to 2.4 during peak production periods. The cutoffs used by GLJ for
probable reserves were 13 meters of net pay for 2P reserves and 10 meters of
net pay for 3P reserves.
The evaluations based on constant prices and costs utilize a net bitumen
price derived from pricing data posted as of June 30, 2006. Although June 30,
2006 prices are utilized, production of bitumen is not anticipated to commence
until mid-2007. Accordingly, if product prices from which the net bitumen
price is derived decline, then the present value of future net revenue
associated with reserves and the associated reserves volumes will be less than
those estimated in the GLJ Report and such reductions may be significant. All
evaluations of future revenue are after the deduction of royalties, all
capital/development costs, production costs and well abandonment costs but
before consideration of indirect costs such as administrative, overhead and
other miscellaneous expenses. The estimated future net revenues contained in
the following tables do not necessarily represent the fair market value of
Connacher's reserves. There is no assurance that the forecast and constant
price and cost assumptions contained in the GLJ Report will be attained and
variances could be material. Other assumptions and qualifications relating to
costs and other matters are included in the GLJ Report. The recovery and
reserve estimates of Connacher's properties described herein are estimates
only. The actual reserves on Connacher's oil sands properties may be greater
or less than those calculated.
<<
RESERVES AND NET PRESENT VALUE OF FUTURE NET REVENUE
BASED ON FORECAST PRICES AND COSTS(6)
Before Deducting Income Taxes
Bitumen Discounted At
-------------------------------------------------------------------------
Gross(1) Net(1) 0% 5% 10% 15% 20%
(mbbl) (mbbl) (MM$) (MM$) (MM$) (MM$) (MM$)
-------------------------------------------------------------------------
Proved Plus
Probable
Undeveloped
(2)(3)(5) 79,632 71,059 1,040 502 261 138 69
Proved Plus
Probable Plus
Possible
Undeveloped
(2)(3)(4)(5) 111,629 98,539 1,680 688 331 174 93
After Deducting Income Taxes(8)
Discounted At
---------------------------------------------------------
0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$)
---------------------------------------------------------
Proved Plus
Probable
Undeveloped
(2)(3)(5) 720 342 171 83 33
Proved Plus
Probable Plus
Possible
Undeveloped
(2)(3)(4)(5) 1,154 467 218 108 50
RESERVES AND NET PRESENT VALUE OF FUTURE NET REVENUE
BASED ON CONSTANT PRICES AND COSTS(7)
Before Deducting Income Taxes
Bitumen Discounted At
-------------------------------------------------------------------------
Gross(1) Net(1) 0% 5% 10% 15% 20%
(mbbl) (mbbl) (MM$) (MM$) (MM$) (MM$) (MM$)
-------------------------------------------------------------------------
Proved Plus
Probable
Undeveloped
(2)(3)(5) 79,632 66,357 1,809 973 581 374 253
Proved Plus
Probable Plus
Possible
Undeveloped
(2)(3)(4)(5) 111,805 92,523 2,601 1,211 674 423 286
After Deducting Income Taxes(8)
Discounted At
---------------------------------------------------------
0% 5% 10% 15% 20%
(MM$) (MM$) (MM$) (MM$) (MM$)
---------------------------------------------------------
Proved Plus
Probable
Undeveloped
(2)(3)(5) 1,243 665 394 250 165
Proved Plus
Probable Plus
Possible
Undeveloped
(2)(3)(4)(5) 1,780 823 452 278 182
Notes:
(1) "Gross Reserves" are the Corporation's working interest (operating or
non-operating) share before deducting royalties and without including
any royalty interests of the Corporation. "Net Reserves" are the
Corporation's working interest (operating or non-operating) share
after deduction of royalty obligations, plus the Corporation's
royalty interests in reserves.
(2) "Proved" reserves are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is 90% likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves.
(3) "Probable" reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable reserves.
(4) "Possible" reserves are those additional reserves that are less
certain to be recovered than probable reserves. It is unlikely that
the actual remaining quantities recovered will exceed the sum of the
estimated proved plus probable plus possible reserves.
(5) "Undeveloped" reserves are those reserves expected to be recovered
from known accumulations where a significant expenditure (for
example, when compared to the cost of drilling a well) is required to
render them capable of production. They must fully meet the
requirements of the reserves classification (proved, probable,
possible) to which they are assigned.
(6) The pricing assumptions used in the GLJ Report with respect to values
of future net revenue (forecast) as well as the inflation rates used
for operating and capital costs are set forth below. GLJ is an
independent qualified reserves evaluator appointed pursuant to
NI 51-101.
Heavy Oil Natural Gas Inflation Rate Exchange Rate
Proxy (12 API) Alberta
at Hardisity Spot Gas
($Cdn/bbl) ($/mcf) %/year US$/$Cdn
-------------------------------------------------------------------------
Forecast
2007 42.50 6.50 2.0 0.890
2008 40.00 8.25 2.0 0.890
2009 37.25 8.10 2.0 0.890
2010 36.00 7.75 2.0 0.890
2011 37.25 7.35 2.0 0.890
2012 38.25 7.15 2.0 0.890
2013 39.25 7.30 2.0 0.890
2014 39.75 7.45 2.0 0.890
2015 40.75 7.65 2.0 0.890
2016 41.50 7.80 2.0 0.890
Thereafter +2%/yr +2%/yr 2.0 0.890
(7) The product prices used in the constant price and cost evaluations in
the GLJ Report were as follows: West Texas Intermediate crude oil at
Cushing, Oklahoma: $73.93 US$D/bbl; Alberta Spot gas at AECO-C:
$5.14/mmbtu; and light crude oil at Edmonton: $85.28/bbl and a
bitumen wellhead price of $44.34/bbl.
(8) Estimations of future income tax expenses included in the GLJ Report
relate solely to estimated unclaimed costs and tax losses, tax
credits and allowances in respect of the Great Divide project.
>>
Oil and Gas Resources
Only Pod One has sufficient well and seismic control to warrant the
assignment of reserves. The other five pods have insufficient drilling
density, seismic mapping or project definition to be categorized as reserves
at this time. Additional drilling and seismic activity could result in
upgrading these to reserve status over time. In the interim, a range of
contingent resources was assigned to reflect uncertainties. The GLJ Report
provided calculations of Contingent Resources comprised of "Low Estimate
Resources ((greater than) 15 meter Pay) - higher certainty" together with
"Best Estimate Resources ((greater than) 13 meter Pay) - likely certainty" and
"High Estimate Resources ((greater than) 10 meter Pay) - lower certainty". Low
Estimate recoverable resources are comprised of mapped original oil-in-place
assigned to Pod One ((greater than) 15 meter Pay) with a lower recovery factor
than are applied to the estimate of 2P reserves. Best Estimate Resources are
comprised of 2P remaining recoverable reserves together with an estimate of
recoverable resources attributable to five other pods on Connacher's lands.
High Estimate Resources (lower certainty) include 3P recoverable reserves at
Pod One together with recoverable resources at the other five pods on
Connacher's acreage, but with a larger areal extent and a higher recovery
factor than attributable under the Best Estimate Category. In addition to
Contingent resources described above, volumes were also estimated for
prospective or undiscovered resources. No prospective resources were assigned
to the low estimate category.
Calculations of the present value of the future net revenue from
remaining recoverable contingent and prospective resources were included in
the GLJ Report. The determination of production forecasts and economic
potential followed a similar methodology to that of the reserves evaluation
cases. Indicative future net revenues for these resource categories were
prepared using scoping estimates as detailed design estimates have not been
prepared.
GLJ forecasts the Low Estimate Reserves and Contingent Resources case
production start-up to occur in mid-2007 with a peak rate of 10,400 barrels of
oil per day achieved by 2014; the Best Estimate Reserve and Contingent
Resources case forecasts production start-up to occur in mid-2007 and a peak
rate of 20,200 barrels of oil per day is achieved by 2017; and the High
Estimate Reserve and Contingent Resources case forecasts production start-up
to occur in mid-2007 with a peak rate of 25,400 barrels of oil per day
achieved by 2017. Utilizing GLJ's forecast for the Reserves, Contingent and
Prospective Resources results in a Best Estimate Reserves and Total Resources
case of production start-up in mid-2007 with a peak rate of 29,900 barrels of
oil per day achieved by 2017 while the High Estimate Reserves and Total
Resources production starts up in mid-2007 with a peak rate of 40,200 barrels
of oil per day achieved by 2012.
<<
SUMMARY OF RESERVES AND RESOURCES VALUES
BASED ON FORECAST PRICES AND COSTS(6)
Low Best High
Estimate Estimate Estimate Low Best High
Reserves Reserves Reserves Estimate Estimate Estimate
Plus Plus Plus Reserves Reserves Reserves
Contin- Contin- Contin- + + +
gent gent gent Total Total Total
Resour- Resour- Resour- Resour- Resour- Resour-
ces ces ces ces ces ces
-------------------------------------------------------------------------
ORIGINAL OIL-IN-PLACE
(mbbl) 167 396 483 167 545 855
DEVELOPED ORIGINAL
OIL-IN-PLACE (mbbl) 150 356 459 150 491 819
MARKETABLE RESERVES
Bitumen (mbbl)
Gross
Reserves(1) 62,949 185,260 261,567 62,949 254,427 459,162
Net Reserves(1) 57,077 166,189 233,227 57,077 228,573 406,225
BEFORE TAX PRESENT
VALUE (MM$)
0% 708 2,530 3,728 708 3,305 6,999
5% 369 998 1,428 369 1,349 2,522
10% 194 427 604 194 576 1,049
15% 96 177 256 96 229 459
20% 37 52 87 37 56 183
AFTER TAX PRESENT
VALUE (MM$)
0% 495 1,729 2,539 495 2,251 4,750
5% 251 662 945 251 885 1,666
10% 124 263 374 124 345 655
15% 52 87 132 52 103 249
20% 8 -1 14 8 -17 59
SUMMARY OF RESERVES AND RESOURCES VALUES
BASED ON CONSTANT PRICES AND COSTS(7)
Low Best High
Estimate Estimate Estimate Low Best High
Reserves Reserves Reserves Estimate Estimate Estimate
Plus Plus Plus Reserves Reserves Reserves
Contin- Contin- Contin- + + +
gent gent gent Total Total Total
Resour- Resour- Resour- Resour- Resour- Resour-
ces ces ces ces ces ces
-------------------------------------------------------------------------
MARKETABLE RESERVES
Bitumen (mbbl)
Gross
Reserves(1) 63,140 185,481 286,943 63,140 254,770 459,337
Net Reserves(1) 53,167 155,163 239,435 53,168 213,269 380,579
BEFORE TAX PRESENT
VALUE (MM$)
0% 1,375 4,126 6,400 1,374 5,608 10,520
5% 804 1,900 2,876 804 2,638 4,342
10% 501 1,009 1,485 500 1,392 2,150
15% 326 588 843 326 794 1,202
20% 218 362 507 218 474 722
AFTER TAX PRESENT
VALUE (MM$)
0% 948 2,814 4,358 948 3,818 7,150
5% 551 1,282 1,932 551 1,772 2,913
10% 339 669 976 339 914 1,413
15% 216 379 536 216 504 764
20% 140 223 305 139 283 436
>>
Connacher's current focus is primarily on the construction program at Pod
One in Great Divide. Significant progress has already been made, reflecting
the effectiveness of the company's modular approach and efficient pre-planning
for the construction phase. As at October 30, 2006 the company's engineering
and procurement consultants have confirmed that major equipment shop
construction is over 87 percent completed, mechanical and civil design work
was over 85 percent completed and other components of the project were
well-advanced. Field operations including civil preparation of the plant site
are estimated to be 25 percent complete, including installation of piles for
storage tanks to be field constructed in early 2007 is on schedule. Drilling
plans are also advancing to enable the first 15 steam-assisted gravity
drainage ("SAGD") well pairs to be drilled later this year and in early 2007.
Connacher is also actively recruiting new full-time employees for its
anticipated Great Divide production operations and has successfully commenced
its hiring program. We welcome all new employees associated with the Great
Divide Pod One project and also welcome our developing and productive
relationship with all our consultants and service and supply companies who
will assist Connacher in completing the project in the most timely and
cost-effective manner possible. Connacher is proud of the prospect of being in
the position of having reduced the timeline for projected startup at Great
Divide from first purchase of its acreage in 2004 to less than four years,
which it believes is a record pace of execution.
Outlook
The outlook for Connacher is buoyant, even against the background of
weakened commodity prices for both crude oil and natural gas. The company is
well-financed and has been able to maintain its 100 percent ownership of its
Great Divide SAGD oil sands project without undue dilution of its equity,
while securing medium-term limited recourse debt financing to fund a
significant portion of its prospective capital outlays. Connacher believes
this to be far preferable to short-term bank financing with its vagaries or to
diluting its interest in the project through farmout or joint venture. The
company has retained control of its own destiny to the long term benefit of
its common shareholders.
In 2007 focus will continue to be on Great Divide although other
important work will be carried out on the company's conventional acreage and
at its Montana refinery. A capital budget approaching $250 million is
envisaged for next year, with approximately 80 percent directed to both Pod
One development and startup and to anticipating continued evaluation of
additional pods and undeveloped acreage in the Great Divide region. It is
hoped a formal applications for the next pod at Great Divide will be submitted
early in 2007. Conventional activity will focus on drilling for natural gas at
Marten Creek and other selected regions in northern Alberta, oil development
drilling at Three Hills, Alberta and ongoing projects at Battrum,
Saskatchewan. It is also anticipated over $16 million will be invested in the
Montana refining operation during 2007.
Management's Discussion and Analysis ("MD&A")
The following is dated as of November 8, 2006 and should be read in
conjunction with the unaudited consolidated financial statements of Connacher
Oil and Gas Limited ("Connacher" or the "company") for the three and nine
months ended September 30, 2006 and 2005 as contained in this interim report
and the MD&A and audited financial statements for the years ended December 31,
2005 and 2004 as contained in the company's 2005 annual report. The unaudited
consolidated financial statements for the three and nine months ended
September 30, 2006 have been prepared in accordance with Canadian generally
accepted accounting principles ("GAAP") and are presented in Canadian dollars.
This MD&A provides management's view of the financial condition of the
company and the results of its operations for the reporting periods.
Information contained in this report contains forward-looking information
based on current expectations, estimates and projections of future production,
capital expenditures and available sources of financing. It should be noted
that forward-looking information involves a number of risks and uncertainties
and actual results may vary materially from those anticipated by the company.
There can be no assurance that the plans, intentions or expectations upon
which these forward-looking statements are based will occur. Forward-looking
statements are subject to risks, uncertainties and assumptions, including
those discussed in the company's Annual Information Form for the year ended
December 31, 2005, which include, without limitation, changes in market
conditions, law or governing policy, operating conditions and costs, operating
performance, demand for crude oil and natural gas, price and exchange rate
fluctuation, currency controls, commercial negotiations, regulatory processes
and approvals and technical and economic factors. Although Connacher believes
that the expectations represented in such forward-looking statements are
reasonable, there can be no assurance that such expectations will prove to be
correct.
The forward-looking statements contained herein are expressly qualified
in their entirety by this cautionary statement. The forward-looking statements
included in this MD&A are made as of the date of the MD&A and Connacher
undertakes no obligation to publicly update such forward-looking statements to
reflect new information, subsequent events or otherwise unless so required by
applicable securities laws. Throughout the MD&A, 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.
<<
FINANCIAL AND OPERATING REVIEW
CONVENTIONAL PRODUCTION, PRICING AND REVENUE
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
% %
2006 2005 Change 2006 2005 Change
-------------------------------------------------------------------------
Conventional daily
production / sales
volumes
Crude oil - bbl/d 1,084 808 34 926 713 30
Natural gas -mcf/d 13,028 497 2,521 10,198 1,077 847
-------------------------------------------------------------------------
Combined - boe/d 3,256 891 265 2,626 893 194
-------------------------------------------------------------------------
Product pricing ($)
Crude oil - per bbl 62.53 53.40 17 56.83 42.62 33
Natural gas - per mcf 5.33 1.88 184 5.58 1.21 363
-------------------------------------------------------------------------
Combined - per boe 42.16 49.48 (15) 41.70 35.50 17
-------------------------------------------------------------------------
Conventional oil and
gas revenues ($000's) 12,325 4,055 204 29,892 8,655 245
-------------------------------------------------------------------------
>>
Conventional oil and gas revenues in the third quarter of 2006 were three
times higher than in the third quarter of 2005.
The acquisition of Luke Energy Ltd. on March 16, 2006 was the most
significant factor in this increase, as natural gas sales volumes increased
more than 26 times from last year on a third quarter comparison. Natural gas
selling prices are also up almost three times from 2005, when Argentinean gas
pricing adversely affected corporate natural gas prices.
Increased crude oil production and sales volumes from new wells drilled
in southwest Saskatchewan (net of the impact of ceasing to consolidate
Petrolifera's results) and increased world oil pricing also contributed to the
increase in conventional oil and natural gas revenues in the current quarter.
Natural gas and crude oil sales are now more evenly balanced,
contributing 52 percent and 48 percent, respectively, of total year to date
2006 conventional revenues.
<<
ROYALTIES ON CONVENTIONAL PETROLEUM AND NATURAL GAS SALES
For the three months ended
September 30 2006 2005
------------------------------------------
Total Per boe Total Per boe
-------------------------------------------------------------------------
Royalties ($000's) $3,134 $10.72 $961 $11.73
Percentage of petroleum
and natural gas revenue 25.4% 24%
-------------------------------------------------------------------------
For the nine months ended
September 30 2006 2005
------------------------------------------
Total Per boe Total Per boe
-------------------------------------------------------------------------
Royalties ($000's) $7,318 $10.21 $2,018 $8.28
Percentage of petroleum
and natural gas revenue 24.6% 23%
-------------------------------------------------------------------------
Royalties represent charges against production or revenue by governments
and landowners.
From year to year, royalties can change based on changes to the weighting
in the product mix which is subject to different royalty rates, and rates
usually escalate with increased product prices.
OPERATING EXPENSES AND NETBACKS - CONVENTIONAL
Company Netbacks(1)
For the nine months ended September 30
($000's) 2006 2005 % Change
------------------------------------------------------
Total Per boe Total Per boe Total Per boe
-------------------------------------------------------------------------
Average daily
production (boe/d) 2,626 893 194
Petroleum and
natural gas
revenue 29,892 41.70 $8,655 $35.50 345% 17.4%
Interest & other
income 690 0.96 181 0.74 381 29.7
Royalties (7,318) (10.21) (2,018) (8.28) 362 23.3
-------------------------------------------------------------------------
Net revenue 23,264 32.45 6,818 27.96 341 16.1
Operating costs (5,693) (7.94) (1,799) (7.38) 320 7.6
-------------------------------------------------------------------------
Company netback -
conventional
operations 17,571 24.51 $5,019 $20.58 350 19.1
-------------------------------------------------------------------------
(1) Calculated by dividing related revenue and costs by total boe
produced, resulting in an overall combined company netback. Netbacks
do not have a standardized meaning prescribed by GAAP and, therefore,
may not be comparable to similar measures used by other companies.
This non-GAAP measurement is a useful and widely used supplemental
measure that provides management of Connacher with performance
measures and that provides shareholders and investors with a
measurement of Connacher's efficiency and its ability to fund future
growth through capital expenditures.
Operating Netbacks by Product
For the nine months ended September 30, 2006
($000's) Crude oil Natural gas
------------------------------------------
Total Per bbl Total Per mcf
-------------------------------------------------------------------------
Average daily production 926 bbl/day 10,198 mcf/d
Total revenue 14,369 56.83 15,524 5.58
Royalties (3,518) (13.90) (3,800) (1.36)
Operating costs (2,008) (7.95) (3,685) (1.32)
-------------------------------------------------------------------------
Operating netback 8,843 34.98 8,039 2.90
-------------------------------------------------------------------------
>>
For the third quarter of 2006 operating costs of $2.4 million were 279
percent higher than in the same prior year period, commensurate with increases
in daily sales volumes. On a per unit basis, operating costs increased by
eight percent to $7.94 per boe. The increase in operating costs, both
absolutely and on a per unit basis, reflects the company's increased
production and sales volumes in a higher cost environment.
Primarily as a result of higher product prices, operating netbacks per
boe for the first nine months of 2006 increased 19 percent to $24.51 per boe
compared to $20.58 in the first nine months of 2005.
REFINING REVENUES AND MARGINS
On March 31, 2006, Connacher completed the acquisition of the refining
assets of Montana Refining Company. The assets acquired included the refinery
and certain inventory including refined products. The results reported herein
are for the period from April 1, 2006. In April, 2006 the refinery was shut
down for 20 days for scheduled "turnaround" maintenance. Since resuming
refining operations after the turnaround, certain increased efficiencies have
occurred, and throughput daily volumes have been increased.
The operating results of the refinery since its acquisition to
September 30, 2006 are summarized below.
<<
For the For the year
three months ended to date to
June 30, September 30, September 30,
2006 2006 2006
-------------------------------------------------------------------------
Refinery throughput
-------------------------------------------------------------------------
Crude charged (bbl/d)(1) 6,864 9,613 8,239
Refinery production (bbl/d)(2) 6,932 10,392 8,662
Sales of produced refined
products (bbl/d) 6,266 12,220 9,243
Sales of refined products
(bbl/d)(3) 7,384 12,680 10,032
Refinery utilization (%)(4) 83% 101% 92%
-------------------------------------------------------------------------
(1) Crude charged represents the barrels per day of crude oil processed
at the refinery.
(2) Refinery production represents the barrels per day of refined
products yielded from processing crude and other refinery feedstocks.
(3) Includes refined products purchased for resale.
(4) Represents crude charged divided by total crude capacity of the
refinery. Note refining capacity has been increased to 9,500 bbl/d.
Feedstocks
-------------------------------------------------------------------------
Sour crude oil (%) 98% 92% 94%
Other feedstocks and blends (%) 2% 8% 6%
-------------------------------------------------------------------------
Total 100% 100% 100%
-------------------------------------------------------------------------
Refining sales revenue ($000's) $50,967 $93,752 $144,719
Refining - crude oil and
operating costs ($000's) 47,104 80,242 127,346
-------------------------------------------------------------------------
Refining margin ($000's) $3,863 $13,510 $17,373
-------------------------------------------------------------------------
Refining margin (%) 7.6% 14.4% 12.0%
-------------------------------------------------------------------------
Sales of produced refined products (based on volumes)
-------------------------------------------------------------------------
Gasolines (%) 27% 30% 29%
Diesel fuels (%) 15% 15% 15%
Jet fuels (%) 3% 4% 4%
Asphalt (%) 50% 49% 49%
LPG and other (%) 5% 2% 3%
-------------------------------------------------------------------------
Total 100% 100% 100%
-------------------------------------------------------------------------
Average per barrel sold
Refining sales revenue $75.85 $80.37 $78.83
Less refining - crude oil and
operating costs 70.10 68.78 69.36
-------------------------------------------------------------------------
Refining margin $5.75 $11.59 $9.47
-------------------------------------------------------------------------
Below are reconciliations to the Consolidated Statement of Income for
refining sales and refining - crude oil and operating costs. Due to rounding,
some amounts may not calculate exactly.
Reconciliation of refined product sales to refining sales revenue
-------------------------------------------------------------------------
Average sales price per
barrel sold $75.85 $80.37 $78.83
Sales of refined products (bbl/d) 7,384 12,680 10,032
Number of days in period 91 92 183
-------------------------------------------------------------------------
Refined product sales ($000's) $50,967 $93,752 $144,719
-------------------------------------------------------------------------
Reconciliation of average cost of products per barrel sold to refining -
crude oil and operating costs
-------------------------------------------------------------------------
Average cost of products per
barrel sold $70.10 $68.73 $69.36
Sales of refined products (bbl/d) 7,384 12,680 10,032
Number of days in period 91 92 183
-------------------------------------------------------------------------
Refining - crude oil and
operating costs ($000's) $47,104 $80,242 $127,346
-------------------------------------------------------------------------
>>
The Montana Refining Company achieved outstanding results in the third
quarter. Quarterly revenues increased 83% to $93.8 million, reflecting
increased throughput, increased asphalt sales from inventory and increased
product prices. Due to continuing process optimization the crude capacity of
the refinery has now been increased to 9,500 bbl/d. During the quarter,
refinery utilization was 101% and the operation ran without downtime.
Operations in the previous quarter were limited to 83% utilization due to a
maintenance turnaround conducted in April. Net refining margin has improved to
$13.5 million or $11.59/barrel, an increase of 250% over second quarter
results. In addition to increased prices and throughput, average product costs
have decreased thereby improving margins.
Due to the demand of the summer paving season, asphalt sales volumes and
revenues generated approximately one-half of the refinery's third quarter
revenues. During this same period asphalt production was augmented by sales
from inventory. As sales volumes and revenues decline to lower levels through
the fourth and first quarters, inventory builds to supply the demand of the
subsequent paving season.
EQUITY INTEREST IN PETROLIFERA EARNINGS
Connacher accounts for its 27 percent equity investment in Petrolifera
Petroleum Limited ("Petrolifera") on the equity method basis of accounting. In
the comparative period, Petrolifera was consolidated with Connacher.
Connacher's equity interest share of Petrolifera's earnings in the third
quarter of 2006 was $4.6 million and $7.1 million for the year to date.
DILUTION GAIN
Since November 2004, the company's equity interest in Petrolifera has
been diluted as a result of Petrolifera issuing common shares. In November
2004, the company's equity interest was reduced from 100 percent to 61
percent; in March 2005 it was reduced to 40 percent; in late 2005, it was
further reduced to 33 percent and through out 2006 it was reduced to 27
percent. These reductions resulted in a dilution gain to the company of $3,000
in the year to date for 2006 (2005 - $3 million gain).
INTEREST AND OTHER INCOME
In the third quarter of 2006, the company earned interest of $165,000
(2005 - $128,000) on excess funds invested in secure short-term investments,
and $690,000 for the nine months ended September 30, 2006 (2005 - $181,000).
GENERAL AND ADMINISTRATIVE EXPENSES
In the third quarter of 2006, general and administrative ("G&A") expenses
were $605,000 compared to $553,000 in the third quarter of 2005. The current
year amount was impacted by reclassifying $585,000 of costs associated with
refining operations to operating costs from G&A and the impact of capitalizing
G&A costs directly associated with the development of the company's oil sands
project. For the 2006 year for date, G&A costs of $815,000 have been
capitalized (2005 - $62,000).
STOCK-BASED COMPENSATION
In the year to date, non-cash stock-based compensation costs of
$9.5 million were recorded (2005 - $941,000). These charges reflect the fair
value of all stock options granted and vested in each period. Of this amount,
$6.7 million was expensed (2005 - $941,000) and $2.8 million was capitalized
(2005 - nil). A portion of the amount expensed is included in refining
operating costs. The year over year increase reflects the growth and success
of the corporation and the expanded equity base as a result of prior sales of
common shares from treasury.
FINANCE CHARGES AND FOREIGN EXCHANGE
Certain costs relating to establishing the company's banking facilities
(bankers' fees, legal costs, etc.) are being deferred and amortized over the
periods to which the banking facilities relate. In the year to date, deferred
financing charges of $1.9 million (2005 - nil) and interest of $2.3 million
(2005 - $112,000) were expensed.
The translation of foreign currency denominated assets and liabilities in
the year to date resulted in a foreign exchange loss of $201,000 and a gain of
$30,000 for the first nine months of 2005. The company's main exposure to
foreign currency risk relates to a US$51,000,000 bridge loan, its US-based
refining business and to the pricing of its crude oil sales, which are
denominated in US dollars.
DEPLETION, DEPRECIATION AND ACCRETION ("DD&A")
The amounts reported for DD&A represent depletion charges in respect of
the company's conventional petroleum and natural gas properties, depreciation
of its refinery, depreciation of its administrative assets, accretion expense
related to future abandonment charges estimated in respect of conventional and
refining abandonment liabilities, and amortization of refinery turnaround
maintenance costs.
Depletion expense is calculated using the unit-of-production method based
on total estimated proved reserves; the refinery and administrative assets are
depreciated over their estimated useful lives. The present value of the
company's future abandonment liabilities are reported on the company's balance
sheet and during the period to abandonment, this balance is accreted to the
estimated full future cost.
<<
The table below summarizes the DD&A charges for 2006 and 2005.
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
($000's) 2006 2005 2006 2005
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Depletion of conventional assets 8,350 1,380 20,140 3,649
Depreciation of refinery assets 622 - 1,244 -
Amortization of turnaround costs 643 - 876 -
Other depreciation 222 212 336 257
Accretion 80 21 212 93
-------------------------------------------------------------------------
Total 9,917 1,613 22,808 3,999
-------------------------------------------------------------------------
>>
On a per unit basis, depletion has increased to $28.00 per boe from
$15.00 per boe in the first nine months of 2005. The increase in depletion
expense (both absolute and per unit) is the result of increased depletable
assets due to the Luke acquisition and the cost of new wells drilled.
Capital costs of $94 million (2005 - $10 million) related to the Great
Divide oil sands project, which is in a pre-production state, have been
excluded from depletable costs. Additionally, undeveloped land acquisition
costs of $12.7 million (2005 - $2.3 million) were excluded from the depletion
calculation, while future development costs of $1.6 million (2005 -
$2 million) for proved undeveloped reserves were included in the depletion
calculation.
CEILING TEST
Oil and gas companies are required to compare the recoverable value of
their oil and gas assets to their recorded carrying value at the end of each
reporting period. Excess carrying values over ceiling value are to be written
off against earnings. No write-down was required for any reporting period in
2006 or 2005.
TAXES
The current income tax provision of $4.2 million for the first nine
months of 2006 primarily relates to income taxes expected to be payable by MRC
from its US-based refining business, and Canadian provincial capital taxes.
The future income tax recovery of $2.1 million for the first nine months
of 2006 primarily represents the impact of recently enacted federal and
provincial income tax rate reductions.
At September 30, 2006 the company had approximately $200 million of
deductible resource pools, $15 million of deductible financing costs and
$9 million of non-capital losses which do not expire before 2009.
NET EARNINGS
In the third quarter of 2006, Connacher generated a profit of
$6.8 million ($0.03 per basic and diluted shares outstanding) as a result of
significantly expanded business activities, compared to a loss of $1 million
($0.01 loss per share) in the third quarter of 2005.
For the first nine months of 2006 the company reported a profit of
$3.7 million ($0.02 per basic and diluted share outstanding). This compares to
net earnings of $410,000 or $nil per basic and diluted share for the same 2005
period.
SHARES OUTSTANDING
For the nine months ended September 30, 2006, the weighted average number
of common shares outstanding was 180 million (2005 - 96 million) and the
weighted average number of diluted shares outstanding, as calculated by the
treasury stock method, was 213 million (2005 - 143 million). The substantial
increase in shares outstanding period over period reflects the equity
financings completed by the company and the treasury shares issued as partial
consideration for the Luke and refinery acquisitions.
<<
As at November 9, 2006, the company had the following securities issued
and outstanding:
- 197,878,015 common shares; and
- 15,545,535 share purchase options.
>>
LIQUIDITY AND CAPITAL RESOURCES
A short term working capital deficiency existed at September 30, 2006 as
part of the consideration paid for the refinery acquisition was financed with
cash and short-term borrowings. In early April 2006 the company drew
US$51 million on a bridge loan facility to partially fund the acquisition of
the Montana refinery assets, which closed on March 31, 2006. This bridge loan
was repaid in full on October 20, 2006 from the proceeds of a US$180 million
term loan ("TLB") facility that was fully drawn on that date. The primary
purpose of the TLB is to fund the total estimated remaining costs necessary to
develop the company's first oil sands project at Great Divide in northern
Alberta ("Pod One"). After also depositing US$14 million into an account to
fund the estimated interest costs during the course of completing the Pod One
project, and after paying US$4 million in costs to complete the transaction,
the balance of TLB proceeds of US$111 million will be used solely to fund the
total estimated remaining costs necessary to complete Pod One.
The TLB has a seven year term. Its principal is amortized by one percent
per year commencing in 2008. Additional principal payments will depend on debt
to cash flow ratios. Principal payments on the TLB are not expected to be
significant in the first six years. One half of the TLB floating interest rate
payments were swapped at an all-in fixed rate of 8.516 percent and one half of
the TLB bears interest of London Inter-Bank Offered Rate ("LIBOR") plus 3.25
percent or at US Prime Lending Rate ("Base Rate") plus 2.25 percent.
On October 20, 2006 the company also secured a US$15 million revolving
line of credit ("LOC") to fund the working capital requirements of the
refinery in Great Falls, Montana that was acquired in March 2006. The LOC has
a five year term and bears interest at LIBOR plus three percent or at Base
Rate plus two percent.
The TLB and the LOC are secured by a debenture and mortgage agreements
covering all of the assets of the refinery and all of the company's interest
in the Great Divide oil sands. The TLB and LOC debts are non-recourse to the
company's conventional petroleum and natural gas assets or its investment
holding in Petrolifera Petroleum Limited.
Cash flow from operations before working capital changes ("cash flow"),
cash flow per share and cash flow per boe do not have standardized meanings
prescribed by GAAP and therefore may not be comparable to similar measures
used by other companies. Cash flow includes all cash flow from operating
activities and is calculated before changes in non-cash working capital. The
most comparable measure calculated in accordance with GAAP would be net
earnings. Cash flow is reconciled with net earnings on the Consolidated
Statement of Cash Flows and below. Cash flow per share is calculated by
dividing cash flow by the weighted average shares outstanding; cash flow per
boe is calculated by dividing cash flow by the quantum of crude oil and
natural gas (expressed in boes) sold in the period. Management uses these non-
GAAP measurements for its own performance measures and to provide its
shareholders and investors with a measurement of the company's efficiency and
its ability to fund a portion of its future growth expenditures.
Management believes that Connacher has adequate liquidity, anticipated
cash generation, unused credit and credit capacity to conduct its operations
and to meet its obligations in accordance with its financial plan and budget.
The company maintains no off-balance sheet financial instruments.
Reconciliation of net earnings to cash flow from operations before
working capital changes:
<<
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
($000's) 2006 2005 2006 2005
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net earnings (loss) $6,771 $(1,034) $3,686 $410
Items not involving cash:
Depletion, depreciation
and accretion 9,917 1,613 22,808 3,999
Stock-based compensation 1,478 610 6,672 941
Financing charges (398) - 1,910 -
Future income tax provision
(recovery) 1,414 600 (2,159) 766
Future employee benefits 128 - 253 -
Foreign exchange (gain) loss 163 11 201 (30)
Lease inducement amortization (15) - (45) -
Dilution (gain) loss 49 - (3) (3,020)
Income applicable to non-
controlling interests - 124 - -
Equity interest in Petrolifera
earnings (4,550) 54 (7,139) 54
-------------------------------------------------------------------------
Cash flow from operations before
working capital changes $14,957 $1,978 $26,184 $3,120
-------------------------------------------------------------------------
For the third quarter of 2006, cash flow was $15 million ($0.08 per basic
and diluted share), 656 percent higher than the $2 million ($0.02 per basic
and diluted share) reported in the third quarter of 2005.
CAPITAL EXPENDITURES AND FINANCING ACTIVITIES
For the third quarter of 2006, capital expenditures totaled $41 million
and $376 million for the first nine months. A breakdown of the expenditures
for the first nine months of 2006 follows:
Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
($000's) 2006 2005 2006 2005
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Acquisition of Luke $463 $- $204,643 $-
Acquisition of refinery 307 - 66,333 -
Minor property acquisitions 2,789 477 7,217 1,560
Oil sands expenditures 31,466 720 83,562 6,061
Conventional oil and gas
expenditures 5,733 1,673 13,862 6,946
Refinery expenditures 690 - 948 -
-------------------------------------------------------------------------
$41,449 $2,870 $376,564 $14,567
-------------------------------------------------------------------------
Oil sands expenditures include exploratory core hole drilling, seismic,
lease acquisition and facility costs. In 2006, 31 exploratory core holes were
drilled.
Conventional oil and gas expenditures include costs of drilling,
completing, equipping and working over conventional oil and gas wells as well
as undeveloped land acquisition and seismic expenditures.
Conventional oil and gas gross and net wells drilled in 2006 are as
follows:
Quarter Quarter Quarter
One Two Three Total
-------------------------------------------------------------------------
Conventional wells drilled
(100% working interest) 3 4 6 13
>>
A significant part of the company's capital program is discretionary and
may be expanded or curtailed based on drilling results and the availability of
capital. This is reinforced by the fact that Connacher operates most of its
wells and holds an approximate 87 percent working interest in its conventional
properties, providing the company with operational and timing controls.
The company has recently entered into a 10 year office lease agreement
committing it to pay approximately $1.6 million per year commencing in July
2007.
Great Divide Oil Sands Project, Northern Alberta
The company holds a 99.7 percent working interest in 79,360 acres of oil
sands leases in the Great Divide region of northern Alberta. To date, the
focus has been on an approximate 2,000 acre tract ("Pod One") on which
approximately $100 million has been invested to acquire the oil sands leases,
to delineate the oil bearing reservoir and for certain facilities related to
this project. Total costs for Pod One are expected to approximate $240 million
including contingencies and certain capitalized items. Having received
regulatory approvals, full development of Pod One has been initiated.
Additionally, the company continues to delineate further oil bearing reserves
on a portion of the remaining 77,000 acres at Great Divide.
Recent Financings
In February 2006 the company entered into financing commitment letters
with BNP Paribas, a major international bank, for the following lending
facilities:
<<
(i) a $45 million reserve-based loan and a $10 million revolving
operating loan to finance conventional petroleum and natural gas
projects in Canada. This facility was established on March 16, 2006;
and
(ii) a US$51 million bridge loan to fund a significant portion of the
acquisition of the Montana refinery. This facility was established
on March 31, 2006.
>>
In October 2006, Connacher secured a US$180 million term loan facility
and a US$15 million revolving working capital loan facility for the refinery.
A portion of the term loan was used to repay the US$51 million bridge loan.
The surplus term loan proceeds are to finance all remaining forecast capital
expenditures on Pod One of the company's Great Divide Oil Sands project.
In February 2006, the company issued 19,047,800 common shares at $5.25
per share for gross proceeds of $100 million to fund exploration and
development activities associated with conventional crude oil and natural gas
activities and the Great Divide Oil Sands project, for general corporate
purposes, for working capital and to possibly partially fund the acquisition
of Luke Energy Ltd. Proceeds of the financing were utilized as follows:
<<
($000's) As stated As
at the time actually
of financing applied
-------------------------------------------------------------------------
Gross proceeds $100,000 $100,000
Underwriters commission and issue costs 6,250 6,250
-------------------------------------------------------------------------
Available for exploration and development,
general corporate purposes, for working
capital and to possibly fund a portion
of the Luke acquisition $93,750 $93,750
-------------------------------------------------------------------------
In September 2006, the company issued 5,714,300 common shares on a "flow-
through" basis at $5.25 per common share for gross proceeds of $30 million to
fund exploration activities to further delineate the company's oil sands
properties through the drilling of additional core holes and shooting 3D
seismic. Proceeds of the financing were utilized as follows:
($000's) As stated As
at the time actually
of financing applied
-------------------------------------------------------------------------
Gross proceeds $30,000,075 $30,000,075
Underwriters commission and issue costs 2,075,000 1,883,000
-------------------------------------------------------------------------
$27,925,075 $28,117,075
-------------------------------------------------------------------------
>>
Refer also to the "Liquidity and Capital Resources," above, for a
discussion of the US$180 million and US$15 million debt facilities entered
into in October 2006.
Acquisition of Luke Energy Ltd. ("Luke")
In December 2005 the company entered into a binding letter agreement to
purchase, by way of a Plan of Arrangement, all of the shares of Luke for a
cash consideration of $2.31 per share plus 0.75 of a Connacher common share
for each Luke common share. On March 15, 2006 the Luke shareholders voted to
approve the arrangement and on March 16, 2006 the arrangement was completed by
the payment in total of $91.5 million cash and the issuance of 29.7 million
Connacher common shares from treasury.
Luke is now a wholly-owned subsidiary of Connacher and produces
approximately 2,800 boe/d (90 percent natural gas), largely at Marten Creek in
northern Alberta. It operates most of its high working interest properties.
This production was considered strategic to Connacher, as it provides a
physical hedge to its initial requirements for natural gas to create steam for
the company's (approved) SAGD oil sands project at Great Divide. Based on
current Luke production volumes and anticipated results of further development
programs, the Luke purchase could also provide surplus volumes for sale in the
marketplace or meet possible future Connacher requirements at Great Divide.
Acquisition of Refining Assets in Montana
On March 31, 2006, the company acquired an 8,300 bbl/d refinery located
in Great Falls, Montana, USA for approximately US$55 million, comprised of
cash and one million Connacher common shares which were issued from treasury.
This acquisition was considered strategic to provide Connacher with
protection against wider and more volatile type of heavy crude oil price
differential swings. These have become increasingly frequent in the current
higher oil price environment for the type of heavy oil which would be produced
at Great Divide. Since its acquisition, the refinery has been a profitable and
strong business unit contributing to the company's cash flow.
Connacher completed the purchase of the refining assets and related
inventory through a new wholly-owned subsidiary, Montana Refining Company,
Inc. ("MRC"). Its continued profitability will depend largely on the spread
between market prices for refined petroleum products and the cost of crude
oil.
MRC's principal source of revenue is from the sale of high value light
end products such as gasoline, diesel, and jet fuel in markets in the western
United States. Additionally, MRC sells a high grade asphalt into the local
market. MRC's principal expenses relate to costs of products sold and
operating expenses.
In April 2006, MRC completed a scheduled plant "turnaround" maintenance
program of its refinery facilities. Such turnarounds are normally scheduled
every two to five years. Turnaround costs are capitalized and amortized over
the period to the next scheduled turnaround.
With minimal additional anticipated capital investment, MRC would be
capable of producing low sulfur gasoline ("LSG") as required by September
2008. Management is also studying changes necessary to comply by September
2010 with ultra low sulfur diesel ("ULSD") requirements. MRC will also be
required to make investments of approximately US $2 million before 2010 for
the installation of certain state of the art pollution control equipment.
The above mentioned regulatory compliance items, including the ULSD and
LSG requirements, or other presently existing or future environmental
regulations, could cause management to make additional capital investments
beyond those described above and/or incur additional operating costs to meet
applicable requirements.
On October 22, 2004, the American Jobs Creation Act of 2004 was signed
into law. Among other things, the Act creates tax incentives for small
refiners preparing to produce ULSD. The Act provides an immediate deduction of
75% of certain costs paid or incurred to comply with the ULSD standards and a
tax credit based on ULSD production for up to 25% of those costs. Management
intends to utilize these incentives when it is required to make these required
expenditures.
NEW CRITICAL ACCOUNTING POLICIES ADOPTED BY CONNACHER
MRC's financial results are reported in accordance with Canadian GAAP and
are consolidated with Connacher's other business units. The preparation of
MRC's financial results require certain estimates and judgments that affect
the reported amounts of assets, liabilities, revenues and expenses, and
related disclosure of contingent assets and liabilities as of the date of the
financial statements. Actual results may differ from those estimates under
different assumptions or conditions. Connacher's management considers the
following new MRC accounting policies to be the most critical to understanding
the judgments that are involved and the uncertainties that could impact on the
company's results of operations, financial condition and cash flows.
Inventory Valuation
Crude oil and refined product inventories are stated at the lower of cost
or net realizable value. Since acquiring the refining assets in March 2006,
management re-evaluated the inventory costing method and has chosen the
average cost method. Net realizable value is determined using current
estimated selling prices.
Deferred Maintenance Costs
MRC's refinery units require regular major maintenance and repairs which
are commonly referred to as "turnarounds". Catalysts used in certain refinery
processes also require routine "change-outs". The required frequency of the
maintenance varies by unit and by catalyst, but generally is every two to five
years. Turnaround costs are capitalized and amortized over the period to the
next scheduled turnaround or change-out. In order to minimize downtime during
turnarounds, contract labor as well as maintenance personnel are utilized on a
continuous 24 hour basis. Whenever possible, turnarounds are scheduled so that
some units continue to operate while others are down for maintenance. The
costs of turnarounds are recorded as deferred charges and are amortized over
the expected periods of benefit.
Long-lived Refining Assets
Depreciation and amortization is calculated based on estimated useful
lives and salvage values. When assets are placed into service, estimates are
made with respect to their useful lives that are believed to be reasonable.
However, factors such as competition, regulation or environmental matters
could cause changes to estimates, thus impacting the future calculation of
depreciation and amortization. Long-lived assets are also evaluated for
potential impairment by identifying whether indicators of impairment exist
and, if so, assessing whether the long-lived assets are recoverable from
estimated future undiscounted cash flows. The actual amount of impairment
loss, if any, to be recorded is equal to the amount by which a long-lived
asset's carrying value exceeds its fair value. Estimates of future
discontinued cash flows and fair values of assets require subjective
assumptions with regard to future operating results and actual results could
differ from those estimates.
RISK MANAGEMENT - MRC
Certain strategies could be used to reduce some commodity prices and
operational risks. No attempt will be made to eliminate all market risk
exposures when it is believed the exposure relating to such risk would not be
significant to future earnings, financial position, capital resources or
liquidity or that the cost of eliminating the exposure would outweigh the
benefit. MRC's profitability will depend largely on the spread between market
prices for refined products sold and market prices for crude oil purchased. A
substantial or prolonged reduction in this spread could have a significant
negative effect on earnings, financial condition and cash flows.
Petroleum commodity futures contracts could be utilized to reduce
exposure to price fluctuations associated with crude oil and refined products.
Such contracts could be used principally to help manage the price risk
inherent in purchasing crude oil in advance of the delivery date and as a
hedge for fixed-price sales contracts of refined products. Commodity price
swaps and collar options could also be utilized to help manage the exposure to
price volatility relating to forecasted purchases of natural gas. Contracts
could also be utilized to provide for the purchase of crude oil and other
feedstocks and for the sales of refined products. Certain of these contracts
may meet the definition of a hedge and may be subject to hedge accounting.
The supply and use of heavy crude oil from the company's Great Divide Oil
Sands Project, as a feedstock for the refinery, would provide a physical hedge
to this exposure, as planned.
MRC's operations are subject to normal hazards of operations, including
fire, explosion and weather-related perils. Various insurance coverages,
including business interruption insurance, are maintained in accordance with
industry practices. However, MRC is not fully insured against certain risks
because such risks are not fully insurable, coverage is unavailable, or, in
management's judgment, premium costs are prohibitive in relation to the
perceived risks.
Additionally, the company has recently issued parental guarantees and
indemnifications on behalf of MRC. This is considered to be in the normal
course of business. The company has not entered into any off-balance sheet
arrangements.
EMPLOYEE BENEFITS PLANS
As a consequence of the refinery acquisition and related employment of
refinery personnel, the company's new US subsidiary, MRC, adopted new employee
future benefit plans with effect from March 31, 2006.
A new non-contributory defined benefit retirement plan covers only MRC's
employees from March 31, 2006. MRC's policy is to make regular contributions
in accordance with the funding requirements of the United States Employee
Retirement Income Security Act of 1974. Benefits are to be based on the
employee's years of service and compensation.
MRC also established new defined contribution (US tax code "401(k)")
plans that cover all of its employees from March 31, 2006. The company's
contributions are based on employees' compensation and partially match
employee contributions.
BUSINESS RISKS
Other than as noted above for "Risk Management - MRC," there was no
material change in the company's risks or risk management activities since
December 31, 2005. Connacher's risk management activities are conducted
according to policies and guidelines established by the Board of Directors.
Readers should refer to Connacher's 2005 AIF and the risk management section
of the 2005 annual MD&A.
IMPACT OF NEW ACCOUNTING PRONOUNCEMENTS
The company has assessed new and revised accounting pronouncements that
have been issued but that are not yet effective and has determined that the
following may have a significant impact on the company.
Beginning with the year ending December 31, 2007 the company will be
required to adopt, if applicable, the Canadian Institute of Chartered
Accountants ("CICA") Section 1530, 3251, 3855 and 3865 on "Comprehensive
Income", "Equity", "Financial Instruments - Recognition and Measurement", and
"Hedges" respectively, all of which were issued in January 2005. Under the new
standards additional financial statement disclosure, namely Consolidated
Statement of Other Comprehensive Income, has been introduced that will
identify certain gains and losses, including the foreign currency translation
adjustments and other amounts arising from changes in fair value, to be
temporarily recorded outside the income statement. In addition, all financial
instruments, including derivatives, are to be included in the company's
Consolidated Balance Sheet and measured, in most cases, at fair values.
Requirements for hedge accounting have been further clarified. Although
Connacher is in the process of evaluating the impact of these standards, the
company does not expect the Financial Instruments and Hedges standards to have
a material impact on its Consolidated Financial Statements.
Over the next five years the CICA will adopt its new strategic plan for
the direction of accounting standards in Canada, which was ratified in January
2006. As part of the plan, Canadian GAAP for public companies will converge
with International Financial Reporting Stands ("IFRS") over the next five
years. The company continues to monitor and assess the impact of the
convergence of Canadian GAAP with IFRS.
OUTLOOK
The company's business plan anticipates continued substantial growth.
Emphasis will continue to be on delineating and developing the Great Divide
Oil Sands Project in Alberta while continuing to develop the company's
recently-expanded conventional production base and profitably operating the
Montana refinery. Timing for development and first production from the Great
Divide Oil Sands Project is subject to availability of the component
equipment, access to skilled personnel and availability of drilling rigs.
Additional financing may be required for the Great Divide Oil Sands Project
and the company's conventional petroleum and natural gas assets.
Additional information relating to Connacher, including Connacher's
Annual Information Form, can be found on SEDAR at www.sedar.com.
<<
QUARTERLY RESULTS
2004 2005(3)
-------------------------------------------------------------------------
Three Months Ended Dec 31 Mar 31 Jun 30 Sept 30(3) Dec 31
-------------------------------------------------------------------------
Financial Highlights ($000
except per share amounts)
- Unaudited
Total revenue 1,987 1,857 2,796 3,222 3,542
Cash flow from operations
before working capital
changes(1) 471 265 877 1,978 1,238
Basic, per share(1) 0.01 - 0.01 0.02 0.01
Diluted, per share(1) 0.01 - 0.01 0.02 0.01
Net earnings (loss) (150) 1,673 (230) (1,034) 582
Basic, per share - 0.02 - (0.01) -
Diluted, per share - 0.02 - (0.01) -
Capital expenditures and
acquisitions 3,954 6,047 5,649 2,870 2,241
Proceeds on disposal of
PNG properties (49) - - - -
Bank debt - - 250 - -
Working capital surplus
(deficiency) 3,549 5,588 854 67,440 75,427
Cash on hand (net debt) 3,914 8,286 2,629 67,708 75,511
Shareholders' equity 40,375 41,079 41,090 113,081 129,108
Operating Highlights -
Conventional
Production/sales volumes
Natural gas - mcf/d 1,290 1,328 1,416 497 86
Crude oil - bbl/d 646 629 702 808 775
Equivalent - boe/d(2) 861 850 938 891 789
Pricing
Crude oil - $/bbl 30.68 30.02 41.23 53.40 41.54
Natural gas - $/mcf 1.29 1.18 0.99 1.88 7.55
Selected Highlights -
$/boe(2)
Weighted average sales price 24.93 24.04 32.35 49.48 41.61
Other income 0.15 0.24 0.41 1.57 7.15
Royalties 4.64 4.82 8.06 11.73 7.76
Operating costs 7.98 7.01 7.42 7.69 8.90
Netback(4) 12.47 12.45 17.28 31.63 32.09
Operating Highlights - Refining
Refining production - bbl/d
Net sales per barrel sold ($)
Refining margin ($)
Common Share Information
Shares outstanding at
end of period (000's) 89,627 92,753 93,013 134,236 139,940
Weighted average share
outstanding for the period
Basic (000's) 50,908 91,189 92,875 103,851 136,071
Diluted (000's) 53,329 94,197 95,555 106,397 142,507
Volume traded during
quarter (000's) 25,256 40,486 16,821 180,848 100,246
Common share price ($)
High 0.80 1.22 1.05 2.69 4.20
Low 0.29 0.49 0.68 0.76 1.09
Close (end of period) 0.55 0.93 0.82 2.54 3.84
-------------------------------------------------------------------------
2006(5)
-------------------------------------------------------
Three Months Ended Mar 31 June 30 Sept 30
-------------------------------------------------------
Financial Highlights ($000
except per share amounts)
- Unaudited
Total revenue 4,446 64,614 103,108
Cash flow from operations
before working capital
changes(1) 1,725 9,499 14,957
Basic, per share(1) 0.01 0.05 0.08
Diluted, per share(1) 0.01 0.05 0.08
Net earnings (loss) (666) (2,419) 6,771
Basic, per share - (0.01) 0.03
Diluted, per share - (0.01) 0.03
Capital expenditures and
acquisitions 300,836 34,280 41,449
Proceeds on disposal of
PNG properties - - -
Bank debt 17,600 70,365 62,380
Working capital surplus
(deficiency) (11,061) (42,483) (39,942)
Cash on hand (net debt) (4,527) 7,505 14,450
Shareholders' equity 337,584 340,639 378,730
Operating Highlights -
Conventional
Production/sales volumes
Natural gas - mcf/d 2,600 15,172 13,028
Crude oil - bbl/d 689 1,026 1,084
Equivalent - boe/d(2) 1,122 3,554 3,256
Pricing
Crude oil - $/bbl 40.93 61.45 62.53
Natural gas - $/mcf 6.34 5.66 5.33
Selected Highlights -
$/boe(2)
Weighted average sales price 39.83 41.88 42.16
Other income 4.20 0.04 0.55
Royalties 8.02 10.43 10.72
Operating costs 8.24 7.63 7.99
Netback(4) 27.77 23.86 24.00
Operating Highlights - Refining
Refining production - bbl/d 6,932 10,392
Net sales per barrel sold ($) 75.85 80.37
Refining margin ($) 5.75 11.59
Common Share Information
Shares outstanding at
end of period (000's) 191,257 191,924 197,878
Weighted average share
outstanding for the period
Basic (000's) 154,152 191,672 193,587
Diluted (000's) 160,574 198,931 200,572
Volume traded during
quarter (000's) 148,184 80,347 48,849
Common share price ($)
High 6.07 5.05 4.55
Low 3.47 3.10 3.09
Close (end of period) 4.95 4.30 3.60
-------------------------------------------------------
(1) Cash flow from operations before working capital changes and cash
flow per share do not have standardized meanings prescribed by
Canadian generally accepted accounting principles ("GAAP") and
therefore may not be comparable to similar measures used by other
companies. Cash flow includes all cash flow from operating activities
and is calculated before changes in non-cash working capital. The
most comparable measure calculated in accordance with GAAP would be
net earnings. Cash flow is reconciled with net earnings on the
Consolidated Statement of Cash Flows and in the accompanying
Management Discussion & Analysis. Management uses these non-GAAP
measurements for its own performance measures and to provide its
shareholders and investors with a measurement of the company's
efficiency and its ability to fund a portion of its future growth
expenditures.
(2) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 mcf : 1 bbl. Boes may be misleading, particularly if
used in isolation. 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.
(3) In the third quarter of 2005, the company discontinued consolidating
the financial and operational results of Petrolifera Petroleum
Limited. Comparative figures have not been restated.
(4) Netback is a non-GAAP measure used by management as a measure of
operating efficiency and profitability. It is calculated as petroleum
and natural gas revenue less royalties and operating costs. Refer to
MD&A for netbacks by product type.
(5) Reflects the financial and operating results relating to the
acquisition of Luke following closing on March 16, 2006, and the
Montana refinery subsequent to its acquisition on March 31, 2006.
CONSOLIDATED BALANCE SHEETS
Connacher Oil and Gas Limited
(Unaudited)
September December
($000's) 30, 2006 31, 2005
-------------------------------------------------------------------------
ASSETS
CURRENT
Cash and cash equivalents $14,450 $75,511
Accounts receivable 35,474 1,605
Refinery inventories (Note 6) 18,635 -
Prepaid expenses 2,309 407
Due from Petrolifera (Note 5) - 221
-----------------------
70,868 77,744
Property, plant and equipment 330,586 45,242
Investment in Petrolifera (Note 5) 17,638 10,496
Other assets 4,275 256
Future income tax asset - 1,075
Goodwill (Note 3) 103,661 -
-----------------------
$527,028 $134,813
-----------------------
LIABILITIES
CURRENT
Accounts payable $48,408 $2,316
Bank debt (Note 7) 62,380 -
-----------------------
Due to Petrolifera (Note 5) 22 -
-----------------------
110,810 2,316
Future employee benefits 251 -
Asset retirement obligations (Note 8) 6,363 3,108
Deferred credits 236 281
Future income tax liability 30,638 -
-----------------------
148,298 5,705
SHAREHOLDERS' EQUITY
Share capital and contributed surplus (Note 9) 374,288 127,033
Cumulative translation adjustment (1,319) -
Retained earnings 5,761 2,075
-----------------------
378,730 129,108
-----------------------
$527,028 $134,813
-----------------------
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
Connacher Oil and Gas Limited
(Unaudited)
($000's, except per Three months ended Nine months ended
share amounts) September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
REVENUE
Petroleum and natural gas
revenue, net of royalties $9,191 $3,094 $22,575 $6,637
Refining sales 93,752 - 144,719 -
Interest and other income 165 128 690 181
-----------------------------------------------
103,108 3,222 167,984 6,818
-----------------------------------------------
EXPENSES
Petroleum and natural gas
operating costs 2,393 631 5,693 1,799
Refining - crude oil and
operating costs 80,242 - 127,346 -
General and administrative 605 553 2,780 1,805
Stock-based compensation
(Note 9) 1,139 610 6,334 941
Finance charges 993 36 4,231 112
Foreign exchange loss (gain) 163 11 201 (30)
Depletion, depreciation
and accretion 9,917 1,613 22,808 3,999
-----------------------------------------------
95,452 3,454 169,393 8,626
-----------------------------------------------
Earnings (loss) before
taxes and other items 7,656 (232) (1,409) (1,808)
Current income tax
provision (recovery) 3,972 24 4,206 (18)
Future income tax
provision (recovery) 1,414 600 (2,159) 766
-----------------------------------------------
5,386 624 2,047 748
-----------------------------------------------
Earnings (loss) before
other items 2,270 (856) (3,456) (2,556)
Equity interest in
Petrolifera earnings
(loss) (Note 5) 4,550 (54) 7,139 (54)
Dilution gain (loss)
(Note 5) (49) - 3 3,020
-----------------------------------------------
Non-controlling interests
(Note 5) - (124) - -
NET EARNINGS (LOSS) 6,771 (1,034) 3,686 410
RETAINED EARNINGS
(DEFICIT), BEGINNING OF
PERIOD (1,010) 2,655 2,075 1,211
-----------------------------------------------
RETAINED EARNINGS, END
OF PERIOD $5,761 $1,621 $5,761 $1,621
-----------------------------------------------
EARNINGS (LOSS) PER
SHARE (Note 11)
Basic 0.03 (0.01) 0.02 -
Diluted 0.03 (0.01) 0.02 -
CONSOLIDATED STATEMENTS OF CASH FLOW
Connacher Oil and Gas Limited
(Unaudited)
($000's) Three months ended Nine months ended
September 30 September 30
-------------------------------------------------------------------------
2006 2005 2006 2005
Cash provided by (used in)
the following activities:
OPERATING
Net earnings (loss) $6,771 $(1,034) $3,686 $410
Items not involving cash:
Depletion, depreciation
and accretion 9,917 1,613 22,808 3,999
Stock-based compensation 1,478 610 6,672 941
Financing charges (398) - 1,910 -
Future employee benefits 128 - 253 -
Future income tax
provision (recovery) 1,414 600 (2,159) 766
Foreign exchange loss
(gain) 163 11 201 (30)
Dilution (gain) loss 49 - (3) (3,020)
Lease inducement
amortization (15) - (45) -
Loss applicable to
non-controlling
interests - 124 - -
Equity interest in
Petrolifera (earnings)
losses (4,550) 54 (7,139) 54
-----------------------------------------------
Cash flow from operations
before working capital
changes 14,957 1,978 26,184 3,120
Change in non-cash
working capital
(Note 11 (b)) 8,636 3,182 (24,335) 3,075
-----------------------------------------------
23,593 5,160 1,849 6,195
-----------------------------------------------
FINANCING
Issue of common shares,
net of share issue costs 28,270 70,506 123,558 72,138
Issue of shares by
Petrolifera, net of
share issue costs - - - 6,228
Deferred financing costs 548 - (2,245) -
Increase (decrease) in
bank debt (7,985) (250) 62,380 -
-----------------------------------------------
20,833 70,256 183,693 78,366
-----------------------------------------------
INVESTING
Acquisition of Luke Energy
Ltd. (Note 3) (38) - (92,677) -
Acquisition of refining
assets (Note 4) 767 - (61,273) -
Acquisition and development
of oil and gas properties (41,752) (2,870) (105,589) (14,567)
Acquisition of other assets - - (5,185) -
Change in non-cash working
capital (Note 11 (b)) 3,603 (1,489) 17,294 28
-----------------------------------------------
(37,420) (4,359) (247,430) (14,539)
-----------------------------------------------
NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS 7,006 71,057 (61,888) 70,022
EFFECT OF EXCHANGE RATE
CHANGES ON CASH AND CASH
EQUIVALENTS (61) - 827 -
IMPACT ON CASH RESULTING
FROM DECONSOLIDATION OF
PETROLIFERA (Note 5) - (6,228) - (6,228)
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD 7,505 2,879 75,511 3,914
-----------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD 14,450 67,708 14,450 67,708
-----------------------------------------------
SUPPLEMENTARY INFORMATION
- (Note 11)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Connacher Oil and Gas Limited
Period ended September 30, 2006
(unaudited)
1. FINANCIAL STATEMENT PRESENTATION
The consolidated financial statements include the accounts of Connacher
Oil and Gas Limited and its subsidiaries (collectively "Connacher" or the
"company") and are presented in accordance with Canadian generally
accepted accounting principles. In Canada and in the United States
through a wholly owned subsidiary, Montana Refining Company, Inc. ("MRC")
the company is in the business of exploring, producing, refining and
marketing conventional petroleum and natural gas and has recently
commenced exploration and development of bitumen in the oil sands of
northern Alberta.
2. SIGNIFICANT NEW ACCOUNTING POLICIES
The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as the
annual audited Consolidated Financial Statements for the year ended
December 31, 2005. The disclosures provided below do not conform in all
respects to those included with the annual audited Consolidated Financial
Statements. The interim Consolidated Financial Statements should be read
in conjunction with the annual audited Consolidated Financial Statements
and the notes thereto for the year ended December 31, 2005.
As a result of the March 2006 acquisition of Luke Energy Ltd. and the
March 2006 purchase of refining assets, the company has adopted the
following new significant accounting policies.
Seasonality of refining operations
Due to the demand of the summer paving season, asphalt sales volumes and
revenues generated approximately one-half of the refinery's third quarter
revenues. During this same period asphalt production was augmented by
sales from inventory. As sales volumes and revenues decline to lower
levels through the fourth and first quarters, inventory builds to supply
the demand of the subsequent paving season.
Refinery inventories
Crude oil and refined product inventories are stated at the lower of cost
or net realizable value. Since acquiring the refining assets in March
2006, management re-evaluated the inventory costing method and has
changed its method of accounting from LIFO to the average cost method.
The change did not have a significant impact and no adjustment was
recorded. Net realizable value is determined using current estimated
selling prices.
Long-lived refining assets
Depreciation and amortization is calculated based on estimated useful
lives and salvage values. Long-lived assets are evaluated for potential
impairment by identifying whether indicators of impairment exist and, if
so, assessing whether the long-lived assets are recoverable from
estimated future undiscounted cash flows. The actual amount of impairment
loss, if any, to be recorded is equal to the amount by which a long-lived
asset's carrying value exceeds its fair value.
Goodwill
Goodwill is the excess purchase price over the fair value of identifiable
assets and liabilities acquired. Goodwill impairment is assessed annually
at year end, or more frequently as economic events dictate, by comparing
its fair value to its carrying value, including goodwill. If the fair
value is less than its carrying value, a goodwill impairment loss is
recognized as the excess of the carrying value of the goodwill over the
fair value of the goodwill.
Foreign currency translation
The company has assessed the operations of MRC to be self-sustaining.
Assets and liabilities of self-sustaining foreign operations are
translated into Canadian dollars at the rate of exchange in effect at the
balance sheet date and revenues and expense are translated at the average
monthly rates of exchange during the periods. Gains or losses on
translation of self-sustaining foreign operations are included in
currency translation adjustment in shareholders' equity.
Pension costs
The company's newly acquired subsidiary, MRC, has a defined benefit
pension plan commencing March 31, 2006 for certain of its employees.
Pension expenses for the plan amount to $253,000 in the current year to
date.
Revenue recognition
Refined product sales and related costs of sales are recognized when
products are shipped and title has passed to customers. All revenues are
reported inclusive of shipping and handling costs incurred and billed on
to customers and exclusive of excise taxes. Shipping and handling costs
incurred are reported in costs of products sold.
Depreciation of refining assets
Depreciation is calculated by the straight-line method over the estimated
useful lives of the assets, primarily 10 to 20 years for refining
facilities, three to five years for transportation vehicles, 10 to
40 years for buildings and improvements and 7 to 30 years for other fixed
assets.
Cost classifications
Costs of products sold include the cost of crude oil, other feedstocks,
blendstocks and purchased finished products, inclusive of transportation
costs. To provide the desired crude oil to the refinery, crude oil is
purchased from producers and other petroleum companies through crude oil
buy/sell exchange contracts. Operating expenses include direct costs of
labor, maintenance materials and services, utilities, marketing expenses
and other direct operating costs. General and administrative expenses
include compensation, professional services and other support costs.
Deferred maintenance costs
Refinery units require regular major maintenance and repairs which are
commonly referred to as "turnarounds". Catalysts used in certain refinery
processes also require regular "changeouts". The required frequency of
the maintenance varies by unit and by catalyst, but generally is every
two to five years. Turnaround costs are deferred and amortized over the
period until the next scheduled turnaround. Other repairs and maintenance
costs are expensed when incurred.
Environmental liabilities
Environmental liabilities are recorded when site restoration and
environmental remediation and cleanup obligations are either known or
considered probable and can be reasonably estimated. Recoveries of
environmental costs through insurance, indemnification arrangements or
other sources are recognized to the extent such recoveries are considered
probable.
Derivative instruments
Derivative instruments would be recognized as either assets or
liabilities in the balance sheet and measured at their fair value.
Changes in the derivative instrument's fair value would be recognized in
earnings unless specific hedge accounting criteria are met. Currently,
the company has no derivative instruments.
3. ACQUISITION OF LUKE ENERGY LTD.
The company completed the acquisition of Luke Energy Ltd. ("Luke") on
March 16, 2006. Final closing adjustments have yet to be determined and
some costs of the deal have been estimated. Consequently, the preliminary
purchase equation is estimated as follows:
-------------------------------------------------------------------------
($000's)
-------------------------------------------------------------------------
Net assets acquired:
Petroleum and natural gas assets 153,755
Goodwill 103,661
Asset retirement obligations (Note 8) (2,109)
Working capital (19,308)
Future income tax liability (31,356)
-------------------------------------------------------------------------
Net assets acquired 204,643
-------------------------------------------------------------------------
Consideration paid:
Cash 92,677
Shares (Note 9) 111,966
-------------------------------------------------------------------------
204,643
-------------------------------------------------------------------------
Included in the working capital deficit are capital costs paid or payable
arising from Luke's winter drilling program and for transaction costs
incurred by Luke. Included in cash consideration paid are transaction
costs of $2 million.
The value of the share consideration paid was determined by reference to
the market value of the company's shares at the time of announcing the
acquisition.
4. ACQUISITION OF REFINING ASSETS
On March 31, 2006 the company acquired all of the assets of a refinery in
Great Falls, Montana. Final closing adjustments have yet to be determined
and some costs of the deal have been estimated. Consequently, the
purchase equation is estimated as follows.
-------------------------------------------------------------------------
($000's)
-------------------------------------------------------------------------
Net assets acquired:
Refining assets $46,337
Inventory 19,996
-------------------------------------------------------------------------
Net assets acquired $66,333
Consideration paid:
Cash $61,273
Shares (Note 9) 5,060
-------------------------------------------------------------------------
$66,333
-------------------------------------------------------------------------
Included in cash consideration paid are transaction costs of $2 million.
The value of the share consideration paid was determined by reference to
the market value of the company's shares at the time of announcing the
acquisition.
The purchase agreement commits the vendor to resolve any environmental
liabilities arising over the next five years for environmental matters
existing at the purchase date.
As a means to facilitate the expeditious transition of the ongoing
refinery business, MRC assumed all of the ongoing purchase and sales
contracts with suppliers and customers of the refinery. These contracts
are all short-term in nature and necessitated some guarantees from
Connacher, all considered to be in the normal course of business.
5. INVESTMENT IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA")
The company records its investment in Petrolifera on an equity basis.
Until the end of the second quarter of 2005 this investment was
consolidated.
Under the terms of a Management Services Agreement with Petrolifera,
Connacher provides management, operational, accounting and general and
administrative services necessary or appropriate to manage and operate
Petrolifera. The fee for this service is $15,000 per month until May
2007. The agreement may be immediately terminated for performance failure
by the aggrieved party or upon 30 days prior written notice by Connacher,
or by mutual agreement.
Dilution gains are recognized upon changes to Connacher's equity interest
in Petrolifera as they occur. In 2006, Petrolifera share purchase rights
and share purchase warrants were exercised by other investors resulting
in a reduction of Connacher's equity interest in Petrolifera to
27 percent at September 30, 2006. The exercise of these rights and
warrants generated a dilution loss for the year to date, in the amount of
$3,000.
6. REFINING INVENTORIES
($000's) September 30, 2006
-------------------------------------------------------------------------
Crude oil 1,883
Other raw materials and unfinished products(1) 1,045
Refined products(2) 13,736
Process chemicals(3) 1,030
Repairs and maintenance supplies and other 941
-------------------------------------------------------------------------
18,635
-------------------------------------------------------------------------
(1) Other raw materials and unfinished products include feedstocks and
blendstocks, other than crude oil. The inventory carrying value
includes the costs of the raw materials and transportation.
(2) Refined products include gasoline, jet fuels, diesels, asphalts,
liquid petroleum gases and residual fuels. The inventory carrying
value includes the cost of raw materials including transportation and
direct production costs.
(3) Process chemicals include catalysts, additives and other chemicals.
The inventory carrying value includes the cost of the purchased
chemicals and related freight.
7. BANK LOANS
As at September 30, 2006 the company had available a $45 million reserve-
based revolving loan ("RBL facility") and a $10 million revolving
operating loan to finance conventional petroleum and natural gas projects
in Canada. These facilities have a renewable one year term and are
secured by a fixed and floating charge debenture in the principal amount
of $500 million. Interest at bank prime plus 1/4 percent is to be charged
on amounts borrowed. At September 30, 2006 the company had drawn
$5.5 million on the RBL facility.
In early April 2006 the company drew US $51 million on a bridge loan
facility to partially fund the acquisition of the Montana refinery
assets, which closed on March 31, 2006. The loan did bear interest at
London Inter-Bank Offered Rate ("LIBOR") + 1/2 percent for the first 90
days (adjusted for subsequent quarterly periods), was secured by a
US$500 million demand debenture and pledge agreement. This bridge loan
was repaid in full on October 20, 2006 from the proceeds of a
US$180 million term loan ("TLB") facility that was fully drawn on that
date.
The TLB has a seven year term. Its principal is amortized by one percent
per year commencing in 2008. Additional principal payments will depend on
debt to cash flow ratios. Principal payments on the TLB are not expected
to be significant in the first six years. One half of the TLB floating
interest payments were swapped at an all-in fixed rate of 8.516 percent
and one half of the TLB bears interest of LIBOR plus 3.25 percent or at
US Prime Lending Rate ("Base Rate") plus 2.25 percent.
On October 20, 2006 the company also secured a US$15 million revolving
line of credit ("LOC") to fund the working capital requirements of the
refinery in Great Falls, Montana that was acquired in March 2006. The LOC
has a five year term and bears interest at LIBOR plus three percent or at
Base Rate plus two percent.
The TLB and the LOC are secured by a debenture and mortgage agreements
covering all of the assets of the refinery and all of the company's
interest in the Great Divide oil sands. The TLB and LOC debts are non-
recourse to the company's conventional petroleum and natural gas assets
or its investment holding in Petrolifera.
8. ASSET RETIREMENT OBLIGATIONS
The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of the obligation associated with the
retirement of petroleum and natural gas properties and facilities.
Nine months
ended Year ended
September December
30, 2006 31, 2005
-------------------------------------------------------------------------
($000's)
-------------------------------------------------------------------------
Asset retirement obligations,
beginning of period $3,108 $2,905
Liabilities incurred 366 301
Liabilities acquired (Note 3) 2,109 -
Liabilities settled with Petrolifera
deconsolidation - (442)
Liabilities disposed - (24)
Change in estimates 568 203
Accretion expense 212 165
-------------------------------------------------------------------------
Asset retirement obligations, end of period $6,363 $3,108
-------------------------------------------------------------------------
9. SHARE CAPITAL AND CONTRIBUTED SURPLUS
Authorized
The authorized share capital is comprised of the following:
- Unlimited number of common voting shares
- Unlimited number of first preferred shares
- Unlimited number of second preferred shares
Issued
Only common shares have been issued by the company.
-------------------------------------------------------------------------
Number of Amount
Shares ($000's)
-------------------------------------------------------------------------
Share Capital:
Balance, December 31, 2005 139,940,448 $125,071
Issued for cash in private placement(a) 19,047,800 100,001
Issued for cash in public offering (b) 5,714,300 30,000
Issued for Luke acquisition (Note 3) 29,699,282 111,966
Issued for refinery acquisition (Note 4) 1,000,000 5,060
Issued upon exercise of options(c) 982,365 905
Issued upon exercise of warrants(d) 1,493,820 881
Share issue costs (8,272)
Tax effect of share issue costs 2,924
Tax effect of expenditures renounced
pursuant to the 2005 flow-through issue(e) (5,448)
-------------------------------------------------------------------------
Balance, Share Capital, September 30, 2006 197,878,015 363,088
-------------------------------------------------------------------------
Contributed Surplus:
-------------------------------------------------------------------------
Balance, December 31, 2005 1,962
Fair value of share options granted(b) 9,453
Assigned value of options exercised (215)
-------------------------------------------------------------------------
Balance, Contributed Surplus,September 30, 2006 11,200
-------------------------------------------------------------------------
Total Share Capital and Contributed Surplus:
December 31, 2005 127,033
September 30, 2006 374,288
-------------------------------------------------------------------------
(a) Private placement - 2006
In March 2006 the company issued from treasury 19,047,800 common shares
at $5.25 per share on a private placement basis.
(b) 2006 flow-through common share issue
In September 2006, the company issued from treasury 5,714,300 common
shares on a flow-through basis at $5.25 per share. The company has agreed
to renounce the related resource expenditures of $30 million to the flow-
through investors. The company has until December 31, 2007 to incur the
eligible resource expenditures. As at September 30, 2006 none of these
expenditures have been incurred.
(c) Stock options granted
A summary of the company's outstanding stock option grants, as at
September 30, 2005 and 2006 and changes during those periods are
presented below:
-------------------------------------------------------------------------
2006 2005
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number Exercise Number Exercise
of Shares Price of Shares Price
-------------------------------------------------------------------------
Outstanding, beginning
of period 8,592,600 1.49 3,988,600 0.53
Granted 8,002,300 4.91 3,501,000 1.31
Expired - - (70,000) 0.55
Exercised (982,365) 0.70 (564,500) 0.57
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Outstanding, end of
period 15,612,535 3.29 6,855,100 0.93
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Exercisable, end of
period 5,626,198 2.47 2,832,200 0.85
-------------------------------------------------------------------------
All stock options have been granted for a period of five years. Of the
8,002,300 options granted in 2006, 6,020,000 vest one-third immediately,
one-third one year after grant and one-third two years after grant. The
remaining 1,982,300 vest one-third one year after grant, one-third two
years after grant and one-third three years after grant. The table below
summarizes unexercised stock options.
-------------------------------------------------------------------------
Weighted
Average Remaining
Contractual Life at
Range of Exercise Prices Number Outstanding September 30, 2006
-------------------------------------------------------------------------
$0.20 - $0.99 3,179,235 2.9
$1.00 - $1.99 2,001,000 3.7
$2.00 - $3.99 3,036,000 4.2
$4.00 - $5.56 7,396,300 4.5
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15,612,535
-------------------------------------------------------------------------
In 2006 a compensatory non-cash charge of $9,454,000 (2005 - $941,000)
was recorded, reflecting the fair value of stock options granted and
vested during the period. Of this current amount, $6,334,000 (2005 -
$941,000) was expensed to G&A, $338,000 was charged to refining operating
costs and $2,782,000 (2005 - nil) was capitalized to property and
equipment.
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with weighted average
assumptions for grants as follows:
-------------------------------------------------------------------------
2006 2005
-------------------------------------------------------------------------
Risk free interest rate 4.1% 3.0%
Expected option life (years) 3 3
Expected volatility 49% 53%
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted in the first nine months of 2006 was $1.81 per option (2005 -
$0.47).
(d) Share purchase warrants
A summary of the company's outstanding share purchase warrants, as at
September 30, 2005 and 2006 and changes during the periods are presented
below:
-------------------------------------------------------------------------
2006 2005
-------------------------------------------------------------------------
Outstanding, beginning of period 1,493,820 5,300,525
Exercised (1,493,820) (3,504,005)
Expired - (15,000)
-------------------------------------------------------------------------
Outstanding, end of period - 1,781,520
-------------------------------------------------------------------------
(e) Flow-through shares (2005)
Effective December 31, 2005, the company renounced $15 million of
resource expenditures to flow-through investors. The related tax effect
of $5,448,000 on those expenditures was recorded in 2006. As at
September 30, 2006, the company had incurred all of the required
expenditures related to these flow-through shares.
10. SEGMENTED INFORMATION
In Canada the company is in the business of exploring, producing and
marketing conventional petroleum and natural gas and has recently
commenced exploration and development of bitumen in the oil sands of
northern Alberta. Prior to the de-consolidation of Petrolifera in 2005
(Note 5) it also conducted a conventional petroleum and natural gas
business in Argentina. The significant aspects of these operating
segments are presented below. Included in total Canadian conventional
assets is the company's carrying value of its investment in Petrolifera.
Three months ended
September 30 Canada Argentina USA Canada
-------------------------------------------------------------------------
Conven- Oil Conven- Admini-
($000's) tional Sands tional Refining strative Total
-------------------------------------------------------------------------
2006
Revenues, net of
royalties 9,191 - - 93,752 - 102,943
Equity interest in
Petrolifera
earnings - - - - 4,550 4,550
Dilution gain
(loss) - - - - (49) (49)
Interest and other
income 18 - - 147 - 165
Operating costs 2,393 - - 80,242 - 82,635
General and
administrative - - - - 605 605
Stock-based
compensation - - - - 1,139 1,139
Finance charges 501 - - (977) 1,469 993
Foreign exchange
loss (gain) 83 - 3 (27) 104 163
Depletion,
depreciation and
accretion 8,430 - - 1,265 222 9,917
Taxes (recovery) (135) - - 5,120 401 5,386
Net earnings
(loss) (2,063) - (3) 8,276 561 6,771
Property and
equipment 189,932 96,488 - 43,710 456 330,586
Goodwill 103,661 - - - - 103,661
Capital
expenditures and
acquisitions 8,651 31,465 - 998 335 41,449
Total assets 308,091 95,914 251 105,067 17,705 527,028
2005
-------------------------------------------------------------------------
Revenues, net of
royalties 2,948 - 146 - - 3,094
Equity interest in
Petrolifera loss - - - - (54) (54)
Interest and other
income 123 - 5 - - 128
Operating costs 575 - 56 - - 631
General and
administrative - - 31 - 522 553
Stock-based
compensation - - - - 610 610
Finance charges 32 - 4 - - 36
Foreign exchange
loss (gain) 20 - (9) - - 11
Depletion,
depreciation and
accretion 1,532 - 63 - 18 1,613
Taxes (recovery) 726 - (102) - - 624
Non-controlling
interest - - (124) - - (124)
Net earnings
(loss) 186 - (16) - (1,204) (1,034)
Property and
equipment 31,210 11,326 - - 672 43,208
Capital
expenditures 1,917 720 215 - 18 2,870
Total assets 106,654 11,326 - - 808 118,788
Nine months ended
September 30 Canada Argentina USA Canada
-------------------------------------------------------------------------
Conven- Oil Conven- Admini-
($000's) tional Sands tional Refining strative Total
-------------------------------------------------------------------------
2006
Revenues, net of
royalties 22,575 - - 144,719 - 167,294
Equity interest in
Petrolifera
Earnings - - - - 7,139 7,139
Dilution gain - - - - 3 3
Interest and other
income 431 - - 259 - 690
Operating costs 5,693 - - 127,346 - 133,039
General and
administrative - - - - 2,780 2,780
Stock-based
compensation - - - - 6,334 6,334
Finance charges 801 - 7 1,954 1,469 4,231
Foreign exchange
loss (gain) 115 - 9 (27) 104 201
Depletion,
depreciation and
accretion 20,353 - - 2,119 336 22,808
Taxes (3,294) - - 4,935 406 2,047
Net earnings (loss) (662) - (16) 8,651 (4,287) 3,686
Property and
equipment 189,932 96,488 - 43,710 456 330,586
Goodwill 103,661 - - - - 103,661
Capital
expenditures and
acquisitions 225,276 83,562 - 67,281 445 376,564
Total assets 308,091 95,914 251 105,067 17,705 527,028
2005
-------------------------------------------------------------------------
Revenues, net of
royalties 5,744 - 893 - - 6,637
Equity interest
in Petrolifera
earnings - - - - (54) (54)
Dilution gain
(loss) - - - - 3,020 3,020
Interest and
other income 159 - 22 - - 181
Operating costs 1,480 - 319 - - 1,799
General and
administrative - - 229 - 1,576 1,805
Stock-based
compensation - - - - 941 941
Finance charges 66 - 46 - - 112
Foreign exchange
loss (gain) 3 - (33) - - (30)
Depletion,
depreciation and
accretion 3,443 - 493 - 63 3,999
Taxes (recovery) 784 - (36) - - 748
Net earnings (loss) 127 - (103) - 386 410
Property and
equipment 31,210 11,326 - - 672 43,208
Capital
expenditures 6,666 6,061 1,767 - 73 14,567
Total assets 106,654 11,326 - - 808 118,788
11. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the common shares used in per share
calculations.
-------------------------------------------------------------------------
For the three months ended September 30 2006 2005
-------------------------------------------------------------------------
Weighted average common shares outstanding 193,587 103,851
Dilutive effect of stock options and stock purchase
warrants 6,985 2,546
-------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 200,572 106,397
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the nine months ended September 30
-------------------------------------------------------------------------
Weighted average common shares outstanding 179,948 96,018
Dilutive effect of stock options and stock purchase
warrants 7,187 5,055
-------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 187,135 101,073
-------------------------------------------------------------------------
(b) Net change in non-cash working capital
-------------------------------------------------------------------------
For the three months ended September 30 2006 2005
-------------------------------------------------------------------------
Accounts receivable (595) 275
Due from (to) Petrolifera 248 -
Non-controlling interest in Petrolifera loss - 3,201
Prepaid expenses 122 (170)
Refinery inventories 9,392 -
Accounts payable 3,072 (1,613)
-------------------------------------------------------------------------
Total 12,239 1,693
-------------------------------------------------------------------------
Summary of working capital changes:
-------------------------------------------------------------------------
Operations 8,636 3,182
Investing 3,603 (1,489)
-------------------------------------------------------------------------
12,239 1,693
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the nine months ended September 30
-------------------------------------------------------------------------
Accounts receivable (29,802) (333)
Due from (to) Petrolifera 243 -
Non-controlling interest in Petrolifera loss - 3,612
Prepaid expenses (1,134) (94)
Refinery inventories 1,361 -
Accounts payable 22,291 (82)
-------------------------------------------------------------------------
Total (7,041) 3,103
-------------------------------------------------------------------------
Summary of working capital changes:
-------------------------------------------------------------------------
Operations (24,335) 3,075
Investing 17,294 28
-------------------------------------------------------------------------
(7,041) 3,103
-------------------------------------------------------------------------
(c) Supplementary cash flow information
-------------------------------------------------------------------------
For the three months ended September 30 2006 2005
-------------------------------------------------------------------------
Interest paid 931 17
Income taxes paid - -
Stock-based compensation capitalized 840 -
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the nine months ended September 30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Interest paid 2,322 50
-------------------------------------------------------------------------
Income taxes paid - -
-------------------------------------------------------------------------
Stock-based compensation capitalized 2,782 -
-------------------------------------------------------------------------
12. RESTATEMENT
As a result of a recent adjustment proposed by Canada Revenue Agency to
resource tax pools respecting assets acquired in 2002, the December 31,
2002 balance of property and equipment was increased by $850,000 and the
future income tax asset balance was reduced by $850,000. Additional
depletion of $216,000 ($127,000 net of tax) for 2002 and 2003 was
recorded as an adjustment to the opening balance of retained earnings for
2005. There was no change to net earnings for 2005.
>>
Forward-Looking Statements: This press release contains certain forward-
looking statements within the meaning of applicable securities law. Forward-
looking statements are frequently characterized by words such as "plan",
"expect", "project", "intend", "believe", "anticipate":, "estimate" and other
similar words, or statements that certain events or conditions "may" or "will"
occur. All information relating to reserves, resources and future net-revenue
constitute forward-looking statements and are based upon the independent
evaluation of GLJ. Forward-looking statements are based on the opinions and
estimates of management at the date the statements are made, and are subject
to a variety of risks and uncertainties and other factors that could cause
actual events or results to differ materially from those projected in the
forward-looking statements. These factors include the inherent risks involved
in the exploration and development of oil sands properties, the uncertainties
involved in interpreting drilling results and other geological data,
fluctuating oil prices, the possibility of project cost overruns or
unanticipated costs and expenses, uncertainties relating to the availability
and costs of financing needed in the future and other factors including
unforeseen delays. As an oil sands enterprise in the development stage,
Connacher faces risks, including those associated with exploration,
development, approvals and the ability to access sufficient capital from
external sources. Anticipated exploration and development plans relating to
Connacher's properties in 2007 are subject to change. For a detailed
description of the risks and uncertainties facing Connacher and its business
and affairs, and for definitions of proved, probable and possible reserves and
contingent and prospective resources, readers should refer to Connacher's
Annual Information Form for the year ended December 31, 2005. Connacher
undertakes no obligation to update forward-looking statements if circumstances
or management's estimates or opinions should change, unless required by law.
The reader is cautioned not to place undue reliance on forward-looking
statements. Reports are based on assumptions which means that future net
revenues listed in this release do not represent fair market value.
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Connacher Oil and Gas Limited (CLL) Exchange: Toronto Stock Exchange
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May 23, 2013, 3:11 PM EDT
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Connacher Oil and Gas reports strong financial results for Q3 as Great Divide oil sands project moves closer to production
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