Connacher Reports Record First Quarter
CALGARY, May 9 /CNW/ - Connacher Oil and Gas Limited (TSX - CLL) is
pleased to report that its first quarter 2007 was a record first quarter for
the company since it was reconstituted with new management and capital in
2001. This applies to conventional production, revenue, cash flow, earnings
and capital expenditures, excluding acquisitions. The performance reflects the
positive effect of the company's integrated strategy and includes excellent
counter-seasonal results, actual and relative to budget, from Montana Refining
Company, Inc., our wholly-owned refining company based in Great Falls,
Montana, which was acquired effective March 31, 2006.HIGHLIGHTS
- Conventional production more than doubled, after the sale of
approximately 250 boe/d at the end of 2006
- Revenues rose approximately 18 fold to $65.9 million
- Cash flow from operations, while lower than Q4 2006 due to seasonal
factors for refining, rose 537 percent to $11 million ($0.06 per
share)
- Earnings reached $5 million ($0.03 per share), compared to a loss in
the first quarter of 2006.
- Capital expenditures exceeded $100 million
- Progress at our Great Divide SAGD Pod One project was considerable
Summary Results
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Three months ended March 31 2007 2006 % Change
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FINANCIAL ($000 except per share amounts)
Revenues, net of royalties $65,923 $3,635 1,714
Cash flow from operations(1) 10,980 1,725 537
Per share, basic(1) 0.06 0.01 500
Per share, diluted(1) 0.05 0.01 400
Net earnings (loss) for the period 4,984 (666) 848
Per share, basic and diluted 0.03 - -
Capital expenditures and acquisitions 109,881 300,836 (63)
Cash on hand 66,209 13,073 406
Working capital (deficit) 24,027 (11,061) 317
Long term debt 207,828 - -
Shareholders' equity 384,593 337,584 14
Total assets 757,205 430,353 76
OPERATING
Daily production/sales volumes
Crude oil - bbl/d 905 689 31
Natural gas - mcf/d 9,665 2,600 272
Barrels of oil equivalent - boe/d(2) 2,515 1,122 124
Product pricing
Oil - $/bbl 49.09 40.93 20
Natural gas - $/mcf 7.76 6.34 22
Barrels of oil equivalent - $/boe(2) 47.48 39.83 19
Common shares outstanding (000's)
Weighted average
Basic 198,119 154,152 29
Diluted 200,008 160,574 25
End of period
Issued 198,218 191,257 4
Fully diluted 216,606 200,109 8
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(1) Cash flow from operations before working capital changes ("cash flow
from operations") 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 from operations 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
from operations is reconciled with net earnings on the Consolidated
Statements 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) 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.LETTER TO SHAREHOLDERS
Connacher reported record financial and operating results during the
first quarter of 2007. This reflected healthy energy prices, a solid
performance by our Montana refinery, expanded conventional production and was
accomplished while we embarked on a substantial capital expenditure program,
primarily focused on the development of our first oil sands project at Great
Divide, Pod One.
During the reporting period, approximately half of our net operating
income was derived from our conventional production and about half from our
refinery, underscoring the merits of an integrated approach to the business,
even before Great Divide bitumen production comes onstream. Our Montana
refining operation performed better than expected during what is traditionally
a difficult period for refining and marketing due to winter conditions in our
area of operation.
GREAT DIVIDE
Our focus in the reporting period continued to be clearly on the oil
sands. During the first quarter we accelerated our development and
construction program at Great Divide Pod One, which included residual site
preparation, construction of the main processing plant and drilling of
horizontal well pairs in preparation for the commencement of operations,
targeted for August, 2007. At that time, it is anticipated the plant will be
commissioned and we will begin three months of steaming both the injector and
producer well bores which comprise the SAGD well pairs. Thereafter, production
will commence and should be ramped up towards our objective of 10,000 bbl/d of
bitumen production pursuant to our regulatory and governmental licensed
approvals. This period is not anticipated to be exceedingly protracted given
the quality of reservoir associated with Pod One. Also, as a consequence our
anticipated steam/oil ratios ("SORs") are anticipated to be low compared to
available analogues known to us at this time. However, it should be understood
that actual performance will be the ultimate determinant of SORs and per well
productivity.
Our target has always been to complete our plant construction and be
ready for startup within 300 days of commencement, following the availability
of a suitable plant site on which to construct our facilities, recognizing the
plant is anticipated to have a useful life exceeding 25 years or more. As the
plant is situated on muskeg, suitable preparation of the site was critical to
confidence in having a stable platform on which to build our processing, steam
generating and water handling and cleaning facilities. We made every effort to
manage costs and mitigate overruns by using a modular approach, taking
advantage of the existing proximate infrastructure, including the main paved
highway between Edmonton, Alberta, the provincial capital, and Fort McMurray,
the capital of the oil sands.
Unfortunately, as evidenced by recent developments as described in a
press release issued after the end of the reporting period, our pre-planning
and modular approach served to contribute to our cost control, but recent
events, inflationary pressures, some scope changes and some overlooked items
previously not budgeted, resulted in our estimate to complete the Pod One
plant and related developments increasing by about 13 percent to approximately
$290 million, compared to our earlier estimate of $256 million. Included in
both estimates are sunk costs to identify Pod One and secure the acreage,
among other costs, of $24 million. Also, both estimates contain provision for
capitalized interest related to servicing the Term Loan B indebtedness, which
will be paid prospectively as due and certain operating costs estimates which
will be capitalized until production ramps up and commerciality is obtained
after steaming and then startup.
Connacher had intended to finance a portion of these additional
expenditures through the use of a portion of a bought-deal underwritten
financing for approximately $50 million, comprised of both common equity and
flow-through common equity from treasury, to be issued pursuant to a
short-form prospectus. Unfortunately, the combination of cost overruns and a
minor short-term downturn in the company's conventional production levels,
arising from a variety of reasons, caused the transaction to be terminated by
mutual agreement among the company and members of the underwriting syndicate.
Connacher is now advancing alternative financing arrangements, which will
provide the company with continued financial liquidity. Additional permanent
capital will eventually be required by the company to maintain its growth
profile and achieve its objectives, including timely initiation of and then
completion of construction and development of its second Pod at Great Divide.
In this regard, Connacher intends to submit an application to the Alberta
Energy and Utilities Board ("AEUB") and other related regulators and
government departments, including Alberta Environment ("AE") and Alberta
Sustainable Resource Development ("ASRD") for permission to proceed with the
development of its Pod Two ("Algar Project"). This project is expected to
virtually replicate Pod One in scope and scale at a target output rate of
10,000 bbl/d of bitumen. It was identified and confirmed by drilling of core
holes and by 3D seismic during the past two years or so and is believed to
have the requisite characteristics for sustainable commercial development.
Assuming the application is submitted in late May as anticipated, it would
likely be early 2008 before actual field work could be initiated by Connacher
to build related facilities and infrastructure, although as with Pod One
considerable engineering and design work could proceed throughout the balance
of this year, so the company is fully-prepared to proceed when the regulatory
approval process is completed and stakeholder consultation is also
accomplished. Costs are anticipated to be higher than Pod One due to
inflationary pressures, but attractive economic returns are still anticipated
for this scale of SAGD operations.
During the latter part of 2006 and in the first quarter of 2007,
Connacher completed its 3D seismic program over the balance of its original
lease block and also drilled 81 new core holes, including those in and around
Pod Two and Pod Four. Some of the cores taken from our Pod Two drilling are
among the best, if not the best, and thickest cores, we have yet seen at Great
Divide, including at Pod One where we consider the reservoir to be top decile
in its critical characteristics. We have now completed 131 core holes at Great
Divide, including 11 in 2004, 19 in 2005, 26 in the first and last quarters of
2006 and 75 thus far in 2007. This density of core holes is still considered
relatively modest, as we own or control approximately 2,250 legal
subdividisions or LSDs, which are each 40 acres in size. This underscores in
part the benefit of coordinating 3D seismic with logging and coring in
Connacher's efforts to establish new accumulations or pods.
As a consequence of our new work in 2007, including the considerable
progress on our plant at Pod One, which can impact on reserve recognition and
reserve values as costs have already been incurred, we intend to have our
independent engineering consultant update our reserve report for Great Divide.
It is expected this could take up to two months to complete, so results are
accordingly expected to be available sometime this summer, most likely in July
2007. It should be noted that previous analysis may have already recognized
some of the reserves or resources which might be assigned to Connacher's
acreage in earlier reports, although certain resources may be upgraded to
reserve status and possible reserves may also be upgraded to proved
non-producing status, depending upon the extent and nature of such prior
recognition.
Permanent transportation alternatives continue to be evaluated for our
dilbit production from Pod One. It is anticipated trucking alternatives for
both diluent and dilbit after blending will be utilized, until the correct and
economically viable long-term alternative is defined.
CONVENTIONAL PRODUCTION
Connacher's conventional production averaged 2,515 boe/d during the first
quarter of 2007, a marked increase of 124 percent from levels achieved last
year and occurred despite having sold approximately 250 boe/d in late 2006.
This reflects the impact of some new drilling but mostly the acquisition of
Luke Energy Ltd. ("Luke") in March 2006. Luke has now been amalgamated into
Connacher. While Connacher's total conventional production has declined from
peak levels achieved in mid-2006 immediately after the Luke purchase, this
reflects the nature of some of these properties as they are only accessible
during the winter, generally from January through March and the impact of
having sold some minor/non-strategic properties in December 2006. As a result,
normal declines were expected to occur until we could activate programs during
the first quarter of each year. We had a very successful winter drilling
program and added considerable tested deliverability, estimated at
approximately 11 mmcf/d based on long-term tests, with sustained initial
productivity more likely to be in the 6-7 mmcf/d range. Circumstances and
timing precluded us from tying in these new wells. There are also a number of
additional offset locations which have been identified. Accordingly, their
impact will have to await next winter. Also, certain work over initiatives
were completed but are not yet affecting current production, largely due to
weather and mechanical and other issues related to third party equipment and
services provided in the area. A new discovery at Seal, Alberta, is now
onstream at over one mmcf/d (approximately 170 boe/d).
While we have recently experienced production levels below the first
quarter average, these are being remedied, corrected or overcome and in any
event are of relative limited consequence to the company's overall thrust and
financial results. Separately, we would advise that our independent engineers
are also expected to complete an update of our conventional reserve estimates,
with an effective date of July 1, 2007, on roughly the same timetable as that
contemplated for our oil sands reserves and resources.
MONTANA REFINING
Montana Refining Company, Inc. ("MRCI"), our wholly-owned refining
subsidiary, turned in an excellent quarter. Its operating statistics and
financial performance exceeded our budgetary expectations and overcame
historic seasonal influences, which tend to adversely affect refining and
marketing during winter months, due to low demand for refined products in
general and asphalt in particular. Various factors contributed to this
performance, including higher product prices, better than expected product
yields, higher than expected throughput, a lower crude cost and some positive
developments in the asphalt market.
To mitigate the seasonal fluctuation in asphalt pricing and to allow the
company to operate at a higher utilization rate and profitability than would
otherwise be achievable, we successfully constructed a 150,000 barrel asphalt
storage tank at our refinery. We are very pleased with our investment in MRCI
for its role in providing profitable returns, credit capacity and flexibility
and the prospect of an attractive payout while eventually fulfilling its
intended objective of providing a hedge against heavy oil price differentials,
once bitumen production commences at Great Divide Pod One later this year.
As disclosed in a recent press release, MRCI received notification from
the United States Environmental Protection Agency that its National
Enforcement Investigations Centre would be conducting a Clean Water Act
compliance inspection in respect of the refinery. The purpose of this
inspection was to determine compliance with applicable environmental
legislation, approvals and permits. MRCI cooperated in connection therewith;
the compliance inspection occurred on April 24, 2007, and a report is awaited.
No significant issues appear to have arisen during the review.
Other Developments
Readers are referred to our website at www.connacheroil.com for updated
pictures of the Pod One plant at Great Divide. Click on Operations/Great
Divide/Photo Gallery to view the progress towards completion.
The results of the company's Annual and Special Meeting of Shareholders,
scheduled to be held in Calgary, Alberta on May 10, 2007 at 3:00 PM at the
Calgary Petroleum Club, will be reported and included in our next interim
report.
The company regrets to announce the resignation of Darren Jackson,
Vice-President, Operations effective May 8, 2007.
Connacher remains optimistic about its future. We will complete Pod One
on time and complete current financing initiatives to fund its increased
costs. At the same time we will continue to meet our obligations to all our
suppliers, creditors and lenders and fulfill our responsibilities to our
common shareholders. We retain a significant, valuable and unfettered 26
percent equity investment in Petrolifera Petroleum Limited, which holding has
a current market value in excess of $225 million against our net cash
investment of only $7 million, after a recent exercise of share purchase
warrants. This investment remains a financial safety valve for Connacher,
provides us with equity earnings and exposes Connacher shareholders to
excellent growth potential. We have great growth potential in the oil sands at
Great Divide. We have other solid business units that contribute to our
overall diversity, strength, resilience and financial performance.
We have generated about $50 million of cash flow during the past twelve
months to supplement the debt and equity capital we have secured. This has
enabled Connacher to remain as one of the few, if only, smaller independent
companies active in the oil sands. This has been a considerable accomplishment
which could only have been achieved with the ongoing support of our
shareholders. It is appreciated.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is dated as of May 8, 2007 and should be read in
conjunction with the unaudited consolidated financial statements of Connacher
Oil and Gas Limited ("Connacher" or the "company") for the three months ended
March 31, 2007 and 2006 as contained in this interim report and the MD&A and
audited financial statements for the years ended December 31, 2006 and 2005 as
contained in the company's 2006 annual report. The unaudited consolidated
financial statements for the three months ended March 31, 2007 have been
prepared in accordance with Canadian generally accepted accounting principles
("GAAP") and are presented in Canadian dollars. This MD&A provides
management's view of the financial condition of the company and the results of
its operations for the reporting periods.
Additional information relating to Connacher, including Connacher's
Annual Information Form is on SEDAR at www.sedar.com.FINANCIAL AND OPERATING REVIEW
PETROLEUM AND NATURAL GAS PRODUCTION, PRICING AND REVENUE
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For the three months ended March 31 2007 2006
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Daily production/sales volumes
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Crude oil - bbl/d 905 689
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Natural gas - mcf/d 9,665 2,600
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Combined - boe/d 2,515 1,122
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Product pricing ($)
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Crude oil - per bbl 49.09 40.93
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Natural gas - per mcf 7.76 6.34
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Boe - per boe 47.48 39.83
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Revenue ($000)
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Petroleum and natural gas revenue - gross 10,747 4,022
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Royalties (2,540) (811)
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Petroleum and natural gas revenue - net 8,207 3,211
-------------------------------------------------------------------------In the first quarter of 2007, net petroleum and natural gas revenues were
up 156 percent to $8.2 million from $3.2 million in 2006. This was primarily
attributable to a 272 percent increase in natural gas production and a 31
percent increase in crude oil sales volumes, primarily resulting from the Luke
acquisition in March 2006. Increased conventional product selling prices also
contributed to this increase. Although world oil selling prices were down
approximately eight percent from the first quarter of 2006, the company's
average crude oil selling price increased by 20 percent to $49.09 per barrel
due to the impact of selling higher quality crude oil and NGLs in the current
year. Although North American natural gas prices were down approximately 20
percent from the first quarter of 2006, the company's natural gas sales prices
increased 22 percent in 2007 as a result of achieving much better industry
market pricing for our larger sales volumes in the current year.
In the first quarter of 2007, the company entered into a "costless
collar" contract with a third party to sell approximately one half of its
natural gas production. Mitigating some downside natural gas pricing risk, the
company will receive a minimum of US $7.00 per mmbtu and a maximum of US $9.50
per mmbtu on a national quantity of 5,000 mmbtu/day of natural gas sold
between April 1, 2007 and October 31, 2007. This transaction was not meant to
speculate on future natural gas prices, but rather to protect the downside
risk to the company's cash flow and the lending value of its reserves-based
line of credit, which is considered very important during a period of rapid
growth with significant capital expenditures.ROYALTIES ON PETROLEUM AND NATURAL GAS SALES
For the three months ended 2007 2006
March 31 ----------------------------------------
($000 except per boe) Total Per boe Total Per boe
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Royalties $2,540 $11.22 $811 $8.02
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As a percentage of petroleum
and natural gas revenue 23.6% 20.0%
-------------------------------------------------------------------------Royalties represent charges against production or revenue by governments
and landowners. Royalties in the first quarter of 2007 were $2.5 million
($11.22 per boe, or 23.6 percent of petroleum and natural gas revenue)
compared to $810,000 in 2006 ($8.02 per boe, or 20 percent of petroleum and
natural gas revenue). 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. The increase
from 2006 to 2007 reflects market conditions related to increased product
prices and production volumes.PETROLEUM AND NATURAL GAS ("PNG") OPERATING EXPENSES AND NETBACKS
Petroleum and Natural Gas Netbacks(1)
For the three months ended March 31
2007 2006 % Change
------------------------------------------------------
($000 except per
boe) Total Per boe Total Per boe Total Per boe
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Average daily
production (boe/d) 2,515 1,122
Petroleum and
natural gas
revenue $10,747 $47.48 $4,022 $39.83 173 22
Royalties (2,540) (11.22) (811) (8.02) 241 52
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Net PNG revenue 8,207 36.26 3,211 31.81 155 14
Operating costs (1,932) (8.54) (831) (8.24) 132 4
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PNG netback $6,275 $27.72 $2,380 $23.57 164 18
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(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 with performance measures and
provides shareholders and investors with a measurement of the
company's efficiency and its ability to fund future growth through
capital expenditures. Operating netbacks are reconciled to net
earnings below.In the first quarter of 2007 operating costs of $1.9 million were 132
percent higher than in the same prior period, and on a per unit basis,
increased by four percent to $8.54 per boe reflecting the higher cost
environment in 2007 and the substantial increases in production volumes during
the year. However, higher product prices resulted in higher operating netbacks
in 2007.Reconciliation of PNG Netback to Net Earnings(1)
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For the three months ended
March 31 2007 2006
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($000, except per unit amounts) Total Per boe Total Per boe
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PNG netback as above $6,275 $27.72 $2,380 $23.57
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Interest income 120 0.53 424 4.20
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Refining margin - net 11,198 49.47 - -
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General and administrative (3,584) (15.83) (956) (9.47)
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Stock-based compensation (2,946) (13.02) (395) (3.91)
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Finance charges (446) (1.97) (84) (0.83)
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Foreign exchange (loss) gain 1,702 7.52 (7) (0.07)
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Depletion, depreciation and
amortization (7,357) (32.50) (2,878) (28.50)
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Income taxes (3,878) (17.13) 358 3.54
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Equity interest in Petrolifera
earnings and dilution gain 3,900 17.23 492 4.87
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Net earnings (loss) $4,984 $22.02 $(666) $(6.60)
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(1) Certain income and expense items included in this reconciliation
relate to non-PNG business and, therefore, affect the consolidated
net earnings (loss) per boe calculations.
PNG Operating Netbacks by Product
For the period ended March 31
Crude oil Natural gas
----------------------------------------
Total Per bbl Total Per mcf
2007 ----------------------------------------
($000s, except per unit amounts)
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Average daily production 905 9,665
Revenue $3,997 $49.09 $6,750 $7.76
Royalties (939) (11.53) (1,601) (1.84)
Operating costs (876) (10.76) (1,056) (1.21)
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PNG Netback $2,182 $26.80 $4,093 $4.71
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2006 Crude oil Natural gas
----------------------------------------
Total Per bbl Total Per mcf
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($000s, except per unit amounts)
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Average daily production 689 bbl/d 2,600 mcf/d
Revenue $2,538 $40.93 $1,484 $6.34
Royalties (445) (7.19) (366) (1.56)
Operating costs (529) (8.53) (302) (1.29)
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PNG Netback $1,564 $25.21 $816 $3.49
-------------------------------------------------------------------------Primarily as a result of higher product prices, operating netbacks per
boe for the first quarter of 2007 increased 18 percent to $27.72 per boe
compared to $23.57 in the first quarter of 2006.
REFINING REVENUES AND MARGINS
The quarterly operating results of the Montana refinery since its
acquisition on March 31, 2006 are summarized below.
Seasonality of Refining Operations and Sales
The Montana refinery is subject to a number of seasonal factors which may
cause product sales revenues to vary throughout the year. The refinery's
primary asphalt market is paving for road construction which is predominantly
a summer demand. Consequently, prices and volumes for our asphalt tend to be
higher in the summer and lower in the colder seasons and during the winter
most of the refinery's asphalt production is stored in tankage for sale in the
subsequent summer. Seasonal factors also affect gasoline (higher demand in
summer months) and distillate and diesel (higher winter demand). As a result,
inventory levels, sales volumes and prices can be expected to fluctuate on a
seasonal basis.-----------------------------------------
Refinery throughput - June 30, Sept 30, Dec 31, Mar 31,
three months ended 2006 2006 2006 2007
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Crude charged (bbl/d)(1) 6,864 9,613 9,642 9,621
Refinery production (bbl/d)(2) 6,932 10,392 10,593 10,634
Sales of produced refined
products (bbl/d) 6,266 12,220 9,662 7,777
Sales of refined products
(bbl/d)(3) 7,384 12,680 10,095 8,254
Refinery utilization (%)(4) 83% 101% 101% 101%
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(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 in
the fourth quarter of 2006.
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Feedstocks - June 30, Sept 30, Dec 31, Mar 31,
three months ended 2006 2006 2006 2007
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Sour crude oil (%) 98% 92% 92% 92%
Other feedstocks and blends (%) 2% 8% 8% 8%
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Total 100% 100% 100% 100%
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Revenues and Margins
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Refining sales revenue ($000s) $50,967 $93,752 $67,155 $57,596
Refining - crude oil and
operating costs ($000s) 47,104 80,242 55,322 46,398
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Refining margin ($000s) $3,863 $13,510 $11,833 $11,198
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Refining margin (%) 7.6% 14.4% 17.6% 19.4%
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Sales of Produced Refined Products (Volume %)
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Gasolines (%) 27% 30% 40% 52%
Diesel fuels (%) 15% 15% 22% 27%
Jet fuels (%) 3% 4% 4% 6%
Asphalt (%) 50% 49% 31% 11%
LPG and other (%) 5% 2% 3% 4%
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Total 100% 100% 100% 100%
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Averages per Barrel of Refined Product Sold
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Refining sales revenue $75.85 $80.37 $72.52 $77.53
Less: refining - crude oil
purchases and operating costs 70.10 68.78 59.74 62.46
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Refining margin $5.75 $11.59 $12.78 $15.07
-------------------------------------------------------------------------The Montana refinery achieved strong operating performance in the first
quarter of 2007 running at 97 percent of capacity with no downtime. Although
refining sales revenues of $57.6 million were down 14 percent from the fourth
quarter of 2006, refinery margins increased to 19.4 percent. Sales revenues
were down due to seasonally-reduced asphalt sales as normally expected during
the winter season.
Current period margins were better than expected due to higher than
expected product prices, improved yield of higher value products (gasoline and
diesel) achieved by a lighter crude slate and lower than expected crude supply
costs.
During the quarter the refinery completed construction of a new 150,000
barrel asphalt storage tank. Work is also progressing well on an improved
waste water treatment facility, office expansion, rail loading enhancements
and the enhanced sulphur recovery process. The refinery's new NaSH fuel gas
scrubbing system operated at 99.8 percent compliance. During the second
quarter the company expects to sanction its ultralow sulphur diesel project to
allow the company to produce ultraclean fuels by late 2008.
INTEREST AND OTHER INCOME
In the first quarter of 2007, the company earned interest of $120,000
(March 31, 2006 - $424,000) on excess funds invested in secure short-term
investments.
GENERAL AND ADMINISTRATIVE EXPENSES
In the first quarter of 2007, general and administrative ("G&A") expenses
were $3.6 million compared to $956,000 in the first quarter of 2006, an
increase of 275 percent, reflecting increased costs associated the company's
growth. On a per unit basis, at $15.83 per boe sold, this cost is unusually
high and is expected to be significantly reduced when bitumen production from
Pod One commences. G&A of $290,000 was capitalized in 2007 (2006 - $91,000),
reflecting additional costs incurred respecting the oil sands development in
the pre-production stage.
Non-cash stock-based compensation costs of $3.5 million were recorded in
the first quarter of 2007 (March 31, 2006 -$604,000). These charges reflect
the fair value of all stock options granted and vested in the period. Of this
amount, $2.9 million was expensed (2006 - $395,000) and $546,000 was
capitalized (2006 - $209,000).
FINANCE CHARGES AND FOREIGN EXCHANGE
Financing charges were $446,000 in the first quarter of 2007 compared to
$84,000 reported in the first of quarter of 2006. These charges increased
significantly due to the issuance of new debt in 2006. An unrealized foreign
exchange gain of $1.7 million was recorded in the first quarter of 2007
primarily due to the conversion of the US$180 million oil sands term loan into
Canadian dollars for reporting purposes, as the Canadian dollar strengthened
in the reporting period.
The company's main exposure to foreign currency risk relates to the
pricing of its crude oil sales, which are denominated in US dollars, and the
translation of the US$180 million oil sands term loan. On an economic basis,
the company's crude oil and bitumen reserves hedge the company's exposure to
foreign currency fluctuations of its US dollar denominated oil sands term
loan.
DEPLETION, DEPRECIATION AND ACCRETION ("DD&A")
Conventional oil and gas depletion expense is calculated using the
unit-of-production method based on total estimated proved reserves. Refining
properties and other assets are depreciated over their estimated useful lives.
DD&A in the first quarter of 2007 was $7.4 million, a 156 percent increase
from last year due to increased production volumes and due to the significant
additions made to capital assets in 2006 and 2007. Conventional oil and gas
depletion equates to $25.12 per boe of production compared to $28.50 per boe
last year.
Capital costs of $239.4 million (March 31, 2006 - $36.1 million) related
to the Great Divide oil sands project, which is in the pre-production stage,
and undeveloped land acquisition costs of $16.3 million (2006 - $2.5 million)
were excluded from the depletion calculation, while future development costs
of $3.2 million (2006 - $1.8 million) for proved undeveloped reserves were
included in the depletion calculation.
Included in DD&A is an accretion charge of $191,000 (March 31, 2006 -
$47,000) in respect of the company's estimated asset retirement obligations.
These charges will continue to be necessary in the future to accrete the
currently booked discounted liability of $11.6 million to the estimated total
undiscounted liability of $35.8 million over the remaining economic life of
the company's oil and gas properties.
INCOME TAXES
The income tax provision of $3.9 million in the first three months of
2007 includes a current income tax provision of $2.7 million, principally
related to US refinery operations and a future income tax provision of
$1.2 million reflecting the benefit of increased tax pools during the period.
At March 31, 2007 the company had approximately $33 million of
non-capital losses which do not expire before 2009, $312 million of deductible
resource pools and $19 million of deductible financing costs.
EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA")
Connacher accounts for its 26 percent equity investment in Petrolifera on
the equity method basis of accounting. Connacher's equity interest share of
Petrolifera's earnings in the first three months of 2007 was $3.9 million
(March 31, 2006 - $389,000).
NET EARNINGS
In the first three months of 2007 the company reported earnings of
$5.0 million ($0.03 per basic and diluted share outstanding) compared to a
loss of $666,000 or $nil per basic and diluted share for the first three
months of 2006. Earnings per boe produced were $22.02 compared to a loss of
$6.60 per boe in the first three months of 2006. In 2007, the refinery
contributed significantly to these results.
SHARES OUTSTANDING
For the first three months of 2007, the weighted average number of common
shares outstanding was 198,119,130 (2006 - 154,151,848) and the weighted
average number of diluted shares outstanding, as calculated by the treasury
stock method, was 200,007,743 (2006 - 160,573,785). The substantial increase
in shares outstanding year over year reflects the issuance from treasury of
58 million common shares issued in 2006 for cash proceeds of $130 million and
in connection with the acquisitions of Luke and the Montana refinery assets.As at May 7, 2007, the company had the following securities issued and
outstanding:
- 198,238,448 common shares; and
- 18,270,890 share purchase options.Details of the exercise provisions and terms of the outstanding options
are noted in the consolidated financial statements, included in this interim
report.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2007, the company had working capital of $24 million,
including $66.2 million of cash dedicated to funding the remaining costs of
completing the Pod One oil sands project.
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 boe) 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.
In addition to available cash, unused debt facilities and cash flow,
additional sources of funding in the form of additional equity issuances or
additional debt financing may be utilized to provide sufficient funding for
working capital purposes and for the company's 2007 capital program.
The company's only financial instruments are cash, accounts receivable
and payable, bank debt, the interest rate swap and the natural gas costless
collar. The company maintains no off-balance sheet financial instruments.
As the company's long term bank debt is denominated in US dollars, there
is a foreign exchange risk associated with its repayment using Canadian
currency. As noted above, the company's crude oil selling prices are
established in relation to US dollar denominated markets and, therefore,
provide a partial hedge to this exposure.
The interest rate swap was entered into to mitigate some of the interest
rate volatility associated with the variable interest rate inherent in all of
the company's debt facilities.
The natural gas costless collar is intended to mitigate some downside
natural gas pricing risk and, therefore, protect the risk of reduced cash flow
from operations and the risk of reductions to the lending value of its
conventional banking facilities, which is considered particularly important in
a time of rapid growth with significant capital expenditure.
Reconciliation of net earnings to cash flow from operations before
working capital changes:Three months ended March 31
2007 2006
-------------------------------------------------------------------------
($000s)
-------------------------------------------------------------------------
Net earnings (loss) $4,984 $(666)
Items not involving cash:
Depletion, depreciation and accretion 7,357 2,878
Stock-based compensation 2,946 395
Financing charges - 6
Future employee benefits 130 -
Future income tax provision (recovery) 1,165 (388)
Foreign exchange (gain) loss (1,702) 7
Lease inducement amortization - (15)
Dilution gain - (103)
Equity interest in Petrolifera earnings (3,900) (389)
-------------------------------------------------------------------------
Cash flow from operations before working
capital changes $10,980 $1,725
-------------------------------------------------------------------------In the first quarter of 2007, cash flow was $11 million ($0.06 per basic
and $0.05 per diluted share), 537 percent higher than the $1.7 million
reported ($0.01 per basic and diluted share) for the first three months of
2006. A significant portion of this was contributed by the refinery.
CAPITAL EXPENDITURES AND FINANCING ACTIVITIES
Capital expenditures totaled $110 million in the first quarter of 2007
(first quarter 2006 - $300.8 million). A breakdown of these expenditures
follows:Three months ended March 31
($000) 2007 2006
-------------------------------------------------------------------------
Acquisition of Luke $- $204,000
Acquisition of refinery assets - 67,000
Oil sands expenditures 86,512 25,236
Conventional oil and gas expenditures 20,252 4,600
Refinery expenditures 3,117 -
-------------------------------------------------------------------------
$109,881 $300,836
-------------------------------------------------------------------------Oil sands expenditures include exploratory core hole drilling, seismic,
lease acquisition on Pods One through Six and costs incurred for the
development of Pod One. In the first three months of 2007, 81 exploratory core
holes were drilled. In the first quarter of 2006, 20 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. In 2007, 19 (18 net)
conventional oil and gas wells were drilled, resulting in eight cased gas
wells; one suspended gas well and two suspended oil wells being evaluated; and
eight (seven net) abandoned wells.
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 average of over 90 percent working interest in its PNG
properties, providing the company with operational and timing controls.
Great Divide Oil Sands Project, Northern Alberta
The company holds a 100 percent working interest in approximately 90,000
acres of oil sands leases in northern Alberta. To date, the focus has been on
an approximate 1,586 acre tract ("Pod One") on which approximately $190
million ($19 million of these costs are included in accounts payable at
March 31, 2007) has been incurred to March 31, 2007 to acquire the oil sands
leases, to delineate the oil bearing reservoir, and for facilities related to
the development of a 10,000 bbl/d SAGD project. Capital development costs for
Pod One are expected to approximate $290 million, prior to the commencement of
bitumen production in the latter part of 2007. The remaining costs will be
funded with dedicated cash balances of $66.2 million, available lines of
credit and new financing sources anticipated to be available to the company.
Acquisition of Luke Energy Ltd. ("Luke")
In March 2006 the company closed the purchase of Luke for cash
consideration of $92.7 million and the issuance of 29.7 million Connacher
common shares from treasury.
Luke produced natural gas, largely at Marten Creek in northern Alberta
and operated most of its high working interest properties. This production was
considered strategic to Connacher, as, in Connacher's view, it would provide a
physical hedge to its initial requirements for natural gas to create steam for
the company's SAGD oil sands project (Pod One) at Great Divide. Based on
purchased production volumes and anticipated development programs, the Luke
purchase is anticipated, over time, to provide surplus natural gas volumes for
sale in the marketplace over and above Connacher requirements at Great Divide.
Such volumes may not be physically consumed at Great Divide, but sold to
offset purchases from more proximate supply points. Luke was amalgamated with
Connacher on January 1, 2007.
Acquisition of Refining Assets in Montana
In March 2006, the company acquired an 8,300 bbl/d refinery located in
Great Falls, Montana, USA, for cash of $61 million and one million Connacher
common shares 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. ("MRCI"). Its continued profitability will depend largely on the spread
between market prices for refined petroleum products and the cost of crude
oil.
MRCI'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, MRCI sells a high grade asphalt into the local
market. MRCI's principal expenses relate to crude oil purchases and operating
expenses.
SIGNIFICANT ACCOUNTING POLICIES AND APPLICATION OF CRITICAL ACCOUNTING
ESTIMATES
The significant accounting policies used by the company are described
below. Certain accounting policies require that management make appropriate
decisions with respect to the formulation of estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses.
Changes in these estimates and assumptions may have a material impact on the
company's financial results and condition. The following discusses such
accounting policies and is included herein to aid the reader in assessing the
critical accounting policies and practices of the company and the likelihood
of materially different results being reported. Management reviews its
estimates and assumptions regularly. The emergence of new information and
changed circumstances may result in changes to estimates and assumptions which
could be material and the company might realize different results from the
application of new accounting standards promulgated, from time to time, by
various regulatory rule-making bodies.
The following assessment of significant accounting polices is not meant
to be exhaustive.
Oil and Gas Reserves
Under Canadian Securities Regulators' "National Instrument 51-101-
Standards of Disclosure for Oil and Gas Activities" ("NI 51-101") proved
reserves are those reserves that can be estimated with a high degree of
certainty to be recoverable. In accordance with this definition, the level of
certainty should result in at least a 90 percent probability that the
quantities actually recovered will equal or exceed the estimated reserves. In
the case of probable reserves, which are less certain to be recovered than
proved reserves, NI 51-101 states that it must be equally likely that the
actual remaining quantities recovered will be greater or less than the sum of
the estimated proved plus probable reserves. Possible reserves are those
reserves less certain to be recovered than probable reserves. There is at
least a 10 percent probability that the quantities actually recovered will
exceed the sum of proved plus probable plus possible reserves.
The company's oil and gas reserve estimates are made by independent
reservoir engineers using all available geological and reservoir data as well
as historical production data. Estimates are reviewed and revised as
appropriate. Revisions occur as a result of changes in prices, costs, fiscal
regimes, reservoir performance or a change in the company's plans. The reserve
estimates are also used in determining the company's borrowing base for its
credit facilities and may impact the same upon revision or changes to the
reserve estimates. The effect of changes in proved oil and gas reserves on the
financial results and position of the company is described under the heading
"Full Cost Accounting for Oil and Gas Activities".
Full Cost Accounting for Oil and Gas Activities
The company uses the full cost method of accounting for exploration and
development activities. In accordance with this method of accounting, all
costs associated with exploration and development are capitalized whether
successful or not. The aggregate of net capitalized costs and estimated future
development costs is depleted using the unit-of-production method based on
estimated proved oil and gas reserves.
NEW SIGNIFICANT ACCOUNTING POLICIES
The company has assessed new and revised accounting pronouncements that
have been issued.
In 2007 the company has adopted, as necessary, the Canadian Institute of
Chartered Accountants ("CICA") Sections 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.
BUSINESS RISKS
Connacher is exposed to certain risks and uncertainties inherent in the
oil and gas and refining businesses. Furthermore, being a smaller independent
company, it is exposed to financing and other risks which may impair its
ability to realize on its assets or to capitalize on opportunities which might
become available to it. Additionally, through the company's investment in
Petrolifera which operates in foreign jurisdictions, it has become exposed to
other risks including currency fluctuations, political risk, price controls
and varying forms of fiscal regimes or changes thereto which may impair
Petrolifera's ability to conduct profitable operations.
The risks arising in the oil and gas industry include price fluctuations
for both crude oil and natural gas over which the company has limited control;
risks arising from exploration and development activities; production risks
associated with the depletion of reservoirs and the ability to market
production. Additional risks include environmental and safety concerns.
For the Montana Refinary, 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. MRCI'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.
MRCI'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, MRCI 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, Connacher has issued parental guarantees and
indemnifications on behalf of MRCI. This is considered to be in the normal
course of business.
The company will require a significant amount of natural gas in order to
generate steam for the SAGD process used at Great Divide. The company is
exposed to the risk of changes in the price of natural gas, which could
increase operating costs of the Great Divide project. This risk is mitigated
to a certain extent by the production and sale of natural gas from the
company's gas properties at Marten Creek acquired with the purchase of Luke.
Additionally, the company is exposed to exchange rate fluctuations since
oil prices and its long term debt are denominated in US dollars, while the
majority of its operating and capital costs are denominated in Canadian
dollars. On an economic basis, the company's crude oil and bitumen reserves
hedge the company's exposure to foreign currency fluctuations of its US dollar
denominated term debt.
Bitumen is generally less marketable than light or medium crude oil, and
prices received for bitumen are generally lower than those for crude oil. The
company is therefore exposed to the price differential between crude oil and
bitumen; fluctuations in this differential could have a material impact on the
company's profitability. The purchase of the Montana refinery was meant to
help mitigate this risk exposure.
The company relies on access to capital markets for new equity to
supplement internally generated cash flow and bank borrowings to finance its
growth plans. Periodically, these markets may not be receptive to offerings of
new equity from treasury, whether by way of private placement or public
offerings. This may be further complicated by the limited market liquidity for
shares of smaller companies, restricting access to some institutional
investors. An increased emphasis on flow-through share financings may
accelerate the pace at which junior oil and gas companies become cash-taxable,
which could reduce cash flow available for capital expenditures on growth
projects. Periodic fluctuations in energy prices may also affect lending
policies of the company's banker, whether for existing loans or new
borrowings. This in turn could limit growth prospects over the short run or
may even require the company to dedicate cash flow, dispose of properties or
raise new equity to reduce bank borrowings under circumstances of declining
energy prices or disappointing drilling results.
The success of the company's capital programs as embodied in its
productivity and reserve base could also impact its prospective liquidity and
pace of future activities. Control of finding, development, operating and
overhead costs per boe is an important criterion in determining company
growth, success and access to new capital sources.
The company attempts to mitigate its business and operational risk
exposures by maintaining comprehensive insurance coverage on its assets and
operations, by employing or contracting competent technicians and
professionals, by instituting and maintaining operational health, safety and
environmental standards and procedures and by maintaining a prudent approach
to exploration and development activities. The company also addresses and
regularly reports on the impact of risks to its shareholders, writing down the
carrying values of assets that may not be recoverable.
Furthermore, the company generally relies on equity financing and a bias
towards conservative financing of its operations under normal industry
conditions to offset the inherent risks of oil and gas exploration,
development and production activities. Occasionally the company utilizes
forward sale, fixed price contracts to mitigate reduced product price risk and
foreign exchange risk during periods of price improvement, primarily with a
view to assuring the availability of funds for capital programs and to enhance
the creditworthiness of its assets with its lenders. While hedging activities
may have opportunity costs when realized prices exceed hedged pricing, such
transactions are not meant to be speculative and are considered within the
broader framework of financial stability and flexibility. Management regularly
reviews the need to utilize such financing techniques.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by the company is accumulated, recorded,
processed, summarized and reported to the company's management as appropriate
to allow timely decisions regarding required disclosure. The company's Chief
Executive Officer and Chief Financial Officer have concluded, based on their
evaluation as of the end of the period covered by this MD&A, that the
company's disclosure controls and procedures as of the end of such period are
effective to provide reasonable assurance that material information related to
the company, including its consolidated subsidiaries, is communicated to them
as appropriate to allow timely decisions regarding required disclosure.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the company is responsible for designing adequate internal
controls over the company's financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with Canadian
GAAP. There have been no changes in the company's systems of internal control
over financial reporting that would materially affect, or is reasonably likely
to materially affect, the company's internal controls over financial
reporting.
It should be noted that while the company's Chief Executive Officer and
Chief Financial Officer believe that the company's disclosure controls and
procedures provide a reasonable level of assurance that they are effective and
that the internal controls over financial reporting are adequately designed,
they do not expect that the financial disclosure controls and procedures or
internal control over financial reporting will prevent all errors and fraud. A
control system, no matter how well conceived or operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met. In reaching a reasonable level of assurance, management necessarily
is required to apply its judgment in evaluating the cost-benefit relationship
of possible controls and procedures.
OUTLOOK
The company's business plan anticipates 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.
Additional financing may be required for the Great Divide oil sands project,
the company's conventional petroleum and natural gas assets and for the
Montana refinery.
QUARTERLY RESULTS
Fluctuations in results over the previous eight quarters are due
principally to variations in oil and gas prices and the acquisitions of Luke
Energy and the Montana refinery in 2006, both of which increased revenues
substantially. Additionally, operating and general and administrative costs
increased due to higher staff levels necessitated by the company's growth.
Depletion, depreciation and amortization increased as a result of higher
production volumes and additions to capital assets.-----------------------------------------------------
2005
-----------------------------------------------------
Three Months Ended Jun 30 Sept 30(3) Dec 31
-----------------------------------------------------
Financial Highlights
($000 except per share
amounts) - Unaudited
-----------------------------------------------------
Revenue net of royalties 2,107 3,222 2,978
-----------------------------------------------------
Cash flow from operations
before working capital
changes(1) 877 1,978 1,238
-----------------------------------------------------
Basic, per share(1) 0.01 0.02 0.01
-----------------------------------------------------
Diluted, per share(1) 0.01 0.02 0.01
-----------------------------------------------------
Net earnings (loss) (230) (1,034) 582
-----------------------------------------------------
Basic and diluted
per share - (0.01) -
-----------------------------------------------------
Capital expenditures 5,649 2,870 2,241
-----------------------------------------------------
Proceeds on disposal of
PNG properties - - -
-----------------------------------------------------
Cash on hand 2,629 67,708 75,511
-----------------------------------------------------
Working capital surplus
(deficiency) 854 67,440 75,427
-----------------------------------------------------
Long term debt - - -
-----------------------------------------------------
Shareholders' equity 41,090 113,081 129,108
-----------------------------------------------------
Operating Highlights
-----------------------------------------------------
Daily production/sales
volumes
-----------------------------------------------------
Natural gas - mcf/d 1,416 497 86
-----------------------------------------------------
Crude oil - bbl/d 702 808 775
-----------------------------------------------------
Equivalent - boe/d(2) 938 891 789
-----------------------------------------------------
Product pricing
-----------------------------------------------------
Crude oil - $/bbl 41.23 53.40 41.54
-----------------------------------------------------
Natural gas - $/mcf 0.99 1.88 7.55
-----------------------------------------------------
Selected Highlights
- $/boe(2)
-----------------------------------------------------
Weighted average sales
price 32.35 49.48 41.61
-----------------------------------------------------
Royalties 8.06 11.73 7.76
-----------------------------------------------------
Operating costs 7.42 7.69 8.90
-----------------------------------------------------
PNG netback(4) 16.87 30.06 24.95
-----------------------------------------------------
Common Share Information
-----------------------------------------------------
Shares outstanding at
end of period (000) 93,013 134,236 139,940
-----------------------------------------------------
Weighted average shares
outstanding for the
period
-----------------------------------------------------
Basic (000) 92,875 103,851 136,071
-----------------------------------------------------
Diluted (000) 95,555 106,397 142,507
-----------------------------------------------------
Volume traded during
quarter (000) 16,821 180,848 100,246
-----------------------------------------------------
Common share price ($)
-----------------------------------------------------
High 1.05 2.69 4.20
-----------------------------------------------------
Low 0.68 0.76 1.09
-----------------------------------------------------
Close (end of period) 0.82 2.54 3.84
-----------------------------------------------------
-------------------------------------------------------------------------
2006 2007
-------------------------------------------------------------------------
Three Months Ended Mar 31 Jun 30 Sept 30 Dec 31 Mar 31
-------------------------------------------------------------------------
Financial Highlights
($000 except per share
amounts) - Unaudited
-------------------------------------------------------------------------
Revenue net of royalties 3,635 61,239 103,110 76,700 65,923
-------------------------------------------------------------------------
Cash flow from operations
before working capital
changes(1) 1,725 9,499 14,957 14,015 10,980
-------------------------------------------------------------------------
Basic, per share(1) 0.01 0.05 0.08 0.08 0.06
-------------------------------------------------------------------------
Diluted, per share(1) 0.01 0.05 0.08 0.07 0.05
-------------------------------------------------------------------------
Net earnings (loss) (666) (2,419) 6,771 3,267 4,984
-------------------------------------------------------------------------
Basic and diluted
per share - (0.01) 0.03 0.02 0.03
-------------------------------------------------------------------------
Capital expenditures 300,836 34,280 41,449 74,960 109,881
-------------------------------------------------------------------------
Proceeds on disposal of
PNG properties - - - 10,000 -
-------------------------------------------------------------------------
Cash on hand - 7,505 14,450 142,391 66,209
-------------------------------------------------------------------------
Working capital surplus
(deficiency) (11,061) (42,483) (39,942) 118,626 24,027
-------------------------------------------------------------------------
Long term debt - - - 209,754 207,828
-------------------------------------------------------------------------
Shareholders' equity 337,584 340,639 378,730 385,398 384,593
-------------------------------------------------------------------------
Operating Highlights
-------------------------------------------------------------------------
Daily production/sales
volumes
-------------------------------------------------------------------------
Natural gas - mcf/d 2,600 15,172 12,711 11,291 9,665
-------------------------------------------------------------------------
Crude oil - bbl/d 689 1,026 1,059 1,139 905
-------------------------------------------------------------------------
Equivalent - boe/d(2) 1,122 3,554 3,177 3,021 2,515
-------------------------------------------------------------------------
Product pricing
-------------------------------------------------------------------------
Crude oil - $/bbl 40.93 61.45 62.53 46.65 49.09
-------------------------------------------------------------------------
Natural gas - $/mcf 6.34 5.66 5.33 6.57 7.76
-------------------------------------------------------------------------
Selected Highlights
- $/boe(2)
-------------------------------------------------------------------------
Weighted average sales
price 39.83 41.88 42.16 42.15 47.48
-------------------------------------------------------------------------
Royalties 8.02 10.43 10.72 9.00 11.22
-------------------------------------------------------------------------
Operating costs 8.24 7.63 7.99 9.27 8.54
-------------------------------------------------------------------------
PNG netback(4) 23.57 23.82 23.45 23.88 27.72
-------------------------------------------------------------------------
Common Share Information
-------------------------------------------------------------------------
Shares outstanding at
end of period (000) 191,257 191,924 197,878 197,894 198,218
-------------------------------------------------------------------------
Weighted average shares
outstanding for the
period
-------------------------------------------------------------------------
Basic (000) 154,152 191,672 193,587 193,884 198,119
-------------------------------------------------------------------------
Diluted (000) 160,574 198,931 200,572 204,028 200,008
-------------------------------------------------------------------------
Volume traded during
quarter (000) 148,184 80,347 48,849 46,444 55,292
-------------------------------------------------------------------------
Common share price ($)
-------------------------------------------------------------------------
High 6.07 5.05 4.55 4.43 4.13
-------------------------------------------------------------------------
Low 3.47 3.10 3.09 3.17 3.07
-------------------------------------------------------------------------
Close (end of period) 4.95 4.30 3.60 3.49 3.86
-------------------------------------------------------------------------
(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 from operations before working capital changes
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 from operations before working capital changes 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) PNG 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. Netbacks
by product type are disclosed in the accompanying MD&A.
CONSOLIDATED BALANCE SHEETS
Connacher Oil and Gas Limited
(Unaudited)
-------------------------------------------------------------------------
($000) March 31, December 31,
2007 2006
-------------------------------------------------------------------------
ASSETS
CURRENT
Cash and cash equivalents $ - $ 19,603
Restricted cash (Note 9 (c)) 66,209 122,788
Accounts receivable 31,138 30,956
Refinery inventories (Note 4) 38,995 24,437
Prepaid expenses 1,159 1,525
Due from Petrolifera - 32
-------------------------------------------------------------------------
137,501 199,341
Property and equipment 487,021 384,311
Goodwill 103,676 103,676
Deferred costs 3,510 4,005
Investment in Petrolifera 25,497 21,597
-------------------------------------------------------------------------
$ 757,205 $ 712,930
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
CURRENT
Accounts payable and accrued liabilities $ 72,160 $ 57,571
Income taxes payable 3,137 3,644
Current portion of bank debt 38,100 19,500
Due to Petrolifera 77 -
-------------------------------------------------------------------------
113,474 80,715
Asset retirement obligations (Note 5) 11,556 7,322
Employee future benefits (Note 9 (d)) 513 388
Long term bank debt 207,828 209,754
Future income taxes 39,241 29,353
-------------------------------------------------------------------------
372,612 327,532
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital and contributed surplus (Note 6) 371,272 376,500
Accumulated other comprehensive loss (Note 3) (691) (130)
Retained earnings 14,012 9,028
-------------------------------------------------------------------------
384,593 385,398
-------------------------------------------------------------------------
$ 757,205 $ 712,930
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
Connacher Oil and Gas Limited
Three Months Ended March 31 (Unaudited)
-------------------------------------------------------------------------
($000, except per share amounts) 2007 2006
-------------------------------------------------------------------------
REVENUE
Petroleum and natural gas revenue, net
of royalties $ 8,207 $ 3,211
Refining and marketing sales 57,596 -
Interest and other income 120 424
-------------------------------------------------------------------------
65,923 3,635
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EXPENSES
Petroleum and natural gas operating costs 1,932 831
Refining - crude oil purchases and
operating costs 46,398 -
General and administrative 3,584 956
Stock-based compensation (Note 6) 2,946 395
Finance charges 446 84
Foreign exchange loss (gain) (1,702) 7
Depletion, depreciation and accretion 7,357 2,878
-------------------------------------------------------------------------
60,961 5,151
-------------------------------------------------------------------------
Earnings (loss) before income taxes
and other items 4,962 (1,516)
Current income tax provision 2,713 30
Future income tax provision (recovery) 1,165 (388)
-------------------------------------------------------------------------
3,878 (358)
-------------------------------------------------------------------------
Earnings (loss) before other items 1,084 (1,158)
Equity interest in Petrolifera earnings 3,900 389
Dilution gain - 103
-------------------------------------------------------------------------
NET EARNINGS (LOSS) 4,984 (666)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF PERIOD 9,028 2,075
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $ 14,012 $ 1,409
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EARNINGS PER SHARE (Note 9 (a))
Basic $ 0.03 -
Diluted $ 0.03 -
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Connacher Oil and Gas Limited
Three Months Ended March 31 (Unaudited)
-------------------------------------------------------------------------
($000) 2007
-------------------------------------------------------------------------
Net earnings $ 4,984
Foreign currency translation adjustment, net
of income taxes of $241 (561)
-------------------------------------------------------------------------
Comprehensive income $ 4,423
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Connacher Oil and Gas Limited
Three Months Ended March 31 (Unaudited)
-------------------------------------------------------------------------
($000) 2007
-------------------------------------------------------------------------
Balance, beginning of period $ (130)
Foreign currency translation adjustment (561)
-------------------------------------------------------------------------
Balance, end of period $ (691)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW
Connacher Oil and Gas Limited
Three Months Ended March 31 (Unaudited)
-------------------------------------------------------------------------
($000) 2007 2006
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash provided by (used in) the following activities:
-------------------------------------------------------------------------
-------------------------------------------------------------------------
OPERATING
-------------------------------------------------------------------------
Net earnings (loss) $ 4,984 $ (666)
Items not involving cash:
Depletion, depreciation and accretion 7,357 2,878
Stock-based compensation 2,946 395
Financing charges - 6
Employee future benefits 130 -
Future income tax provision (recovery) 1,165 (388)
Foreign exchange loss (gain) (1,702) 7
Dilution gain - (103)
Lease inducement amortization - (15)
Equity interest in Petrolifera earnings (3,900) (389)
-------------------------------------------------------------------------
Cash flow from operations before working
capital changes 10,980 1,725
Changes in non-cash working capital
(Note 9 (b)) 6,922 4,243
-------------------------------------------------------------------------
17,902 5,968
-------------------------------------------------------------------------
-------------------------------------------------------------------------
FINANCING
Issue of common shares, net of share
issue costs 280 94,922
Increase in bank debt 27,600 17,600
Repayment of bank debt (9,000) -
-------------------------------------------------------------------------
Deferred financing costs - (1,947)
-------------------------------------------------------------------------
18,880 110,575
-------------------------------------------------------------------------
-------------------------------------------------------------------------
INVESTING
Acquisition and development of oil
and gas properties (105,294) (29,556)
Decrease in restricted cash 56,579 -
Acquisition of Luke Energy Ltd. - (92,227)
Acquisition of refining assets - (62,041)
Change in non-cash working capital
(Note 9 (b)) (7,105) 4,844
-------------------------------------------------------------------------
(55,820) (178,980)
-------------------------------------------------------------------------
NET DECREASE IN CASH AND CASH EQUIVALENTS (19,038) (62,437)
-------------------------------------------------------------------------
Impact of foreign exchange on foreign
currency denominated cash balances (565) -
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, BEGINNING
OF PERIOD 19,603 75,511
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ - $ 13,074
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary information - Note 9
-------------------------------------------------------------------------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Connacher Oil and Gas Limited
Period ended March 31, 2007 (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. Operating in
Canada, and in the U.S. through its subsidiary Montana Refining
Company, Inc. ("MRCI"), the company is in the business of exploring,
developing, 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 ACCOUNTING POLICIES
The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as
indicated in the annual audited Consolidated Financial Statements for
the year ended December 31, 2006, except as described in Note 3. 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, 2006.
3. NEW ACCOUNTING STANDARDS
Effective January 1, 2007 the company adopted CICA Handbook sections
1530, 3251, 3855 and 3865 relating to Comprehensive Income, Equity,
Financial Instruments - Recognition and Measurement, and Hedges,
respectively. Under the new standards, additional financial statement
disclosure, namely the Consolidated Statement of Comprehensive
Income, has been introduced. This statement identifies certain gains
and losses, which in the company's case include only foreign currency
translation adjustments arising from translation of the company's
U.S. refining subsidiary which is considered to be self-sustaining,
that are recorded outside the income statement. Additionally, a
separate component of equity, Accumulated Other Comprehensive Income
("AOCI"), has been introduced in the consolidated balance sheet to
record the continuity of other comprehensive income balances on a
cumulative basis.
The adoption of comprehensive income has been made in accordance with
the applicable transitional provisions. Accordingly, the December 31,
2006 period end accumulated foreign currency translation adjustment
balance of $130,000 has been reclassified to AOCI. In addition, the
change in the accumulated foreign currency translation adjustment
balance for the three months ended March 31, 2007 of $561,000 is now
included in the Statement of Comprehensive Income (three months ended
March 31, 2006 - nil). Finally, all financial instruments, including
derivatives, are recorded in the company's consolidated balance sheet
and measured at their fair values.
Under section 3855, the company is required to classify its financial
instruments into one of five categories. The company has classified
all of its financial instruments, with the exception of the oil sands
term loan, as Held for Trading, which requires measurement on the
balance sheet at fair value with any changes in fair value recorded
in income. This classification has been chosen due to the nature of
the company's financial instruments, which, except for the oil sands
term loan, are of a short-term nature such that there are no material
differences between the carrying values and the fair values of these
financial statement components. Transaction costs related to
financial instruments classified as Held for Trading are recorded in
income in accordance with the new standards.
The US $180 million oil sands term loan has been classified as other
liabilities and is accounted for on the amortized cost basis.
The adoption of section 3865, "Hedges", has had no effect on the
company's consolidated financial statements as the company does not
account for its derivative financial instruments as hedges.
---------------------------------------------------------------------
($000) Increase/(Decrease)
---------------------------------------------------------------------
Other comprehensive income (561)
Accumulated other comprehensive income (561)
---------------------------------------------------------------------
Effective January 1, 2007, the company adopted the revised
recommendations of CICA Handbook section 1506, Accounting Changes.
The new recommendations permit voluntary changes in accounting policy
only if they result in financial statements which provide more
relevant and reliable financial information. Accounting policy
changes must be applied retrospectively unless it is impractical to
determine the period or cumulative impact of the change in policy.
Additionally, when an entity has not applied a new primary source of
GAAP that has been issued but is not yet effective, the entity must
disclose that fact along with information relevant to assessing the
possible impact that application of the new primary source of GAAP
will have on the entity's financial statements in the period of
initial application.
As of January 1, 2008, the company will be required to adopt two new
CICA Handbook requirements, section 3862, "Financial Instruments -
Disclosures" and section 3863, "FInancial Instruments - Presentation"
which will replace current section 3861. The new standards require
disclosure of the significance of financial instruments to an
entity's financial statements, the risks associated with the
financial instruments and how those risks are managed. The new
presentation standard essentially carries forward the current
presentation requirements. The company is assessing the impact of
these new standards on its consolidated financial statements and
anticipates that the main impact will be in terms of the additional
disclosures required.
As of January 1, 2008, the company will be required to adopt CICA
Handbook section 1535, "Capital Disclosures" which requires entities
to disclose their objectives, policies and processes for managing
capital and, in addition, whether the entity has complied with any
externally imposed capital requirements. The company is assessing the
impact of this new standard on its consolidated financial statements
and anticipates that the main impact will be in terms of the
additional disclosures required.
4. REFINERY INVENTORIES
Inventories consist of the following:
---------------------------------------------------------------------
($000) March 31, December 31,
2007 2006
---------------------------------------------------------------------
Crude oil $2,777 $3,520
Other raw materials and unfinished
products(1) 1,389 1,292
Refined products(2) 31,716 17,440
Process chemicals(3) 1,745 909
Repairs and maintenance supplies
and other 1,368 1,276
---------------------------------------------------------------------
$ 38,995 $ 24,437
---------------------------------------------------------------------
---------------------------------------------------------------------
(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.
5. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the beginning and ending aggregate
carrying amount of the obligation associated with the company's
retirement of its petroleum and natural gas properties and
facilities.
---------------------------------------------------------------------
($000) Three months Year
ended ended
March 31, December 31,
2007 2006
---------------------------------------------------------------------
Asset retirement obligations,
beginning of period $ 7,322 $ 3,108
Liabilities incurred 4,043 2,384
Liabilities acquired - 2,109
Liabilities disposed - (864)
Change in estimated future cash flows - 237
Accretion expense 191 348
---------------------------------------------------------------------
Asset retirement obligations,
end of period $ 11,556 $ 7,322
---------------------------------------------------------------------
Liabilities incurred in 2007 have been estimated using a discount
rate of eight percent to more accurately reflect the company's
credit-adjusted risk free interest rate given its current capital
structure. The company has not recorded an asset retirement
obligation for the Montana refinery as it is currently the company's
intent to maintain and upgrade the refinery so that it will be
operational for the foreseeable future. Consequently, it is not
possible at the present time to estimate a date or range of dates for
settlement of any asset retirement obligation related to the
refinery.
6. SHARE CAPITAL AND CONTRIBUTED SURPLUS
Authorized
The authorized share capital comprises 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 Amount
of Shares ($000)
---------------------------------------------------------------------
Share Capital:
Balance, December 31, 2006 197,894,015 $ 363,082
Issued upon exercise of options (a) 324,433 289
Tax effect of expenditures renounced
pursuant to the issuance of
flow-through common shares (b) (9,000)
Assigned value of options exercised - 105
Share issue costs (9)
---------------------------------------------------------------------
Balance, Share Capital, March 31, 2007 198,218,448 $ 354,467
---------------------------------------------------------------------
---------------------------------------------------------------------
Contributed Surplus:
Balance, December 31, 2006 $ 13,418
Fair value of share options granted 3,492
Assigned value of options exercised (105)
---------------------------------------------------------------------
Balance, Contributed Surplus, March 31, 2007 $ 16,805
---------------------------------------------------------------------
---------------------------------------------------------------------
Total Share Capital and Contributed Surplus:
---------------------------------------------------------------------
December 31, 2006 $ 376,500
---------------------------------------------------------------------
March 31, 2007 $ 371,272
---------------------------------------------------------------------
(a) Stock Options
A summary of the company's outstanding stock options, as at
March 31, 2007 and 2006 and changes during those periods is presented
below:
---------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Shares Price Shares Price
---------------------------------------------------------------------
Outstanding,
beginning of
period 16,212,490 $ 3.31 8,592,600 $ 1.49
Granted 2,744,833 3.88 335,000 4.80
Exercised (324,433) 0.89 (436,366) (0.73)
Expired (213,000) 3.75 - -
---------------------------------------------------------------------
Outstanding, end
of period 18,419,890 $ 3.44 8,491,234 $ 1.66
---------------------------------------------------------------------
Exercisable, end
of period 9,617,198 $ 3.02 3,192,997 $ 0.96
---------------------------------------------------------------------
All stock options have been granted for a period of five years.
Options granted under the plan are generally fully exercisable after
two or three years and expire five years after the date granted. The
table below summarizes unexercised stock options.
---------------------------------------------------------------------
Weighted
Average
Remaining
Contractual
Life at
Number March 31,
Range of Exercise Prices Outstanding 2007
---------------------------------------------------------------------
$0.20 - $0.99 2,941,802 2.4
$1.00 - $1.99 1,871,000 3.2
$2.00 - $3.99 6,206,833 4.4
$4.00 - $5.56 7,400,255 4.0
---------------------------------------------------------------------
18,419,890
---------------------------------------------------------------------
In 2007 a compensatory non-cash expense of $3.5 million (2006 -
$604,420) was recorded, reflecting the amortization of the fair value
of stock options over the vesting period. Of this amount,
$2.9 million (2006 - $394,180) was expensed and $546,000 (2006 -
$210,000) 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:
---------------------------------------------------------------------
2007 2006
---------------------------------------------------------------------
Risk free interest rate 4.5% 4.1%
Expected option life (years) 3 3
Expected volatility 68% 48%
---------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted in the first quarter of 2007 was $1.86 per option (2006 -
$1.83).
(b) Flow through shares
Effective December 31, 2006, the company renounced $30 million of
resource expenditures to flow-through investors. The related tax
effect of $9 million of these expenditures was recorded in 2007. The
company incurred all of the required expenditures related to these
flow-through shares in 2006 and 2007.
7. COMMODITY PRICE RISK MANAGEMENT
During the first quarter of 2007 the company entered into a costless
collar arrangement whereby the sales price for 5 million cubic feet
per day of the company's natural gas production was fixed within a
range of US$7.00 per mmbtu - US$9.50 per mmbtu. The effective date of
the arrangement commences April 1, 2007 and continues until
October 31, 2007. At March 31, 2007 the fair value of this collar was
a liability of $57,000.
8. SEGMENTED INFORMATION
In Canada, the company is in the business of exploring and producing
conventional petroleum and natural gas and is engaged in the
exploration and development of bitumen in the oil sands of northern
Alberta. In the U.S., the company is in the business of refining and
marketing petroleum products. The significant aspects of these
operating segments are presented below. Included in Canadian
administrative assets is the company's carrying value of its
investment in Petrolifera.
Three months
ended Canada Canada Argentina
March 31 Oil and Administ- USA Oil and
($000) Gas rative Refining Gas Total
---------------------------------------------------------------------
2007
Revenues, net
of royalties $ 8,207 $ - $ 57,596 $ - $ 65,803
Equity interest
in Petrolifera
earnings - 3,900 - - 3,900
Interest and
other income 13 - 107 - 120
Crude oil
purchase and
operating costs 1,932 - 46,398 - 48,330
General and
administrative 3,584 - - - 3,584
Stock-based
compensation - 2,946 - - 2,946
Finance charges 371 - 75 - 446
Foreign exchange
gain (1,702) - - - (1,702)
Depletion,
depreciation
and accretion 6,100 - 1,257 - 7,357
Taxes provision 224 - 3,654 - 3,878
Net earnings
(loss) 2,512 (2,855) 5,327 - 4,984
Property and
equipment, net 433,394 2,132 51,495 - 487,021
Capital
expenditures
and
acquisitions 105,834 1,042 3,117 - 109,993
Total assets 619,242 27,628 110,335 - 757,205
---------------------------------------------------------------------
2006
Revenues, net
of royalties $ 3,211 $ - $ - $ - $ 3,211
Equity interest
in Petrolifera
earnings - 389 - - 389
Dilution gain - 103 - - 103
Interest and
other income 416 - 8 - 424
Operating costs 831 - - - 831
General and
administrative 956 - - - 956
Stock-based
compensation - 395 - - 395
Finance charges 84 - - - 84
Foreign exchange
loss 7 - - - 7
Depletion,
depreciation and
accretion 2,878 - - - 2,878
Taxes (recovery) (358) - - - (358)
Net earnings
(loss) (1,159) 492 8 (7) (666)
Property and
equipment, net 225,965 - 47,104 - 273,069
Capital
expenditures 233,735 - 67,101 - 300,836
Total assets 347,229 11,769 71,221 135 430,354
---------------------------------------------------------------------
9. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the common shares used in per share
calculations.
---------------------------------------------------------------------
For the three months ended March 31 2007 2006
---------------------------------------------------------------------
Weighted average common shares
outstanding 198,119,130 154,151,848
Dilutive effect of stock options
and share purchase warrants 1,888,613 6,421,936
---------------------------------------------------------------------
Weighed average common shares
outstanding - diluted 200,007,743 160,573,785
---------------------------------------------------------------------
(b) Net change in non-cash working capital
---------------------------------------------------------------------
For the three months ended March 31 ($000) 2007 2006
---------------------------------------------------------------------
Accounts receivable $ (182) $ (2,438)
Refinery inventories (14,558) -
Due from Petrolifera 109 (169)
Prepaid expenses 366 (11)
Accounts payable and accrued liabilities 14,589 11,705
Income taxes payable (507) -
---------------------------------------------------------------------
Total $ (183) $ 9,087
---------------------------------------------------------------------
Summary of working capital changes:
---------------------------------------------------------------------
($000) 2007 2006
---------------------------------------------------------------------
Operations $ 6,922 $ 4,243
Investing (7,105) 4,844
---------------------------------------------------------------------
$ (183) $ 9,087
---------------------------------------------------------------------
(c) Supplementary cash flow information
---------------------------------------------------------------------
For the three months ended March 31 2007 2006
---------------------------------------------------------------------
($000)
---------------------------------------------------------------------
Interest paid 5,759 1
Income taxes paid 3,039 -
Stock-based compensation capitalized 546 210
---------------------------------------------------------------------
At March 31, 2007 cash of $66.2 million is restricted for use in
paying expenditures for a designated oil sands project under the
terms of the company's financing arrangements for its oil sands
project.
(d) Defined benefit pension plan
In the first quarter of 2007, $130,000 has been charged to expense in
relation to MRCI's defined benefit pension plan.
10. SUBSEQUENT EVENTS
On April 27, 2007, Connacher exercised 1,714,286 warrants to acquire
1,714,286 common shares of Petrolifera Petroleum Limited for cash
consideration of $5.1 million. This transaction will increase
Connacher's interest in Petrolifera to approximately 26.3% on a fully
diluted basis assuming that all outstanding Petrolifera warrants are
exercised.
In April 2007, the company received notice from its banker that their
scheduled review of the company's conventional line of credit
facility would be deferred until June 15, 2007.Forward-Looking Statements: This press release contains certain "forward-
looking statements" within the meaning of such statements under
applicable securities law including management's assessment of the
anticipated capital costs and the timing of production start-up of the
Pod One Project, the planned development of the Algar Project,
anticipated production from non-oil sands properties and the results of
the compliance inspection pursuant to the Clean Air Act. Forward-looking
statements are frequently characterized by words such as "plan",
"expect", "project", "intend", "believe", "anticipate", "estimate",
"may", "will", "potential", "proposed" and other similar words, or
statements that certain events or conditions "may" or "will" occur. These
statements are only predictions. 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, readers should refer to Connacher's Annual Information Form for
the year ended December 31, 2006 and the short form preliminary
prospectus of Connacher dated April 23, 2007, both of which are available
at www.sedar.com. 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. Barrels of oil
equivalent ("boe") may be misleading, particularly if used in isolation.
A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
For further information:
For further information: Richard A Gusella, President and Chief Executive Officer, Connacher Oil and Gas Limited, Phone: (403) 538-6201, Fax: (403) 538-6225, inquiries@connacheroil.com, Website: www.connacheroil.com