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Connacher reports record cash flow and earnings for second quarter and first half 2007
CALGARY, Aug. 10 /CNW/ - Connacher Oil and Gas Limited (TSX - CLL) had a
wonderful second quarter of 2007. It was highlighted by the completion of our
updated reserve report which showed significant expansion of our bitumen and
conventional reserve base; filing of the application for development of our
Pod Two or "Algar" Project east of Great Divide Pod One (the company's second
10,000 bbl/d oil sands development project); the near completion of our plant
and facilities at Pod One, which completion will be celebrated on August 10,
2007; successful raising of $100 million of new capital through the sale of
low coupon senior unsecured subordinated convertible debentures; and strong
second quarter and first half 2007 financial and operating results resulting
in record cash flow and earnings.
HIGHLIGHTS
- Bitumen reserves grew dramatically - 2P ("proved and probable")
reserves more than doubled to 178 million barrels and 3P ("proved,
probable and possible") reserves increased 120 percent to 242 million
barrels
- 2P Reserves and Best Estimate Total Resources of bitumen rose
60 percent to 417 million barrels; 3P Reserves and High Estimate
Total Resources reached 798 million barrels
- 2P conventional reserves rose 14 percent, including a 27 percent
increase in 2P natural gas reserves due to successful winter 2007
drilling
- 10 percent present value of future net revenues for 2P Reserves and
Best Estimate Total Resources approximately $1.2 billion; 3P Reserves
and High Estimate Total Resources exceeds $1.8 billion
- Pod One construction nearing completion; commissioning ceremony
August 10, 2007 within 300 day construction timetable
- Pod Two ("Algar") application for a second 10,000 bbl/d plant
submitted to Alberta Energy and Utilities Board ("EUB") and other
regulators
- Record cash flow from operations and earnings for second quarter and
first half 2007
- First half earnings reached $27.2 million ($0.14 per share), compared
to a loss in 2006
- Capital expenditures approximated $93 million in the second quarter
and $203 million for the year-to-date 2007
SUMMARY RESULTS
-------------------------------------------------------------------------
Three months ended June 30 Six months ended June 30
-------------------------------------------------------------------------
2007 2006 % Change 2007 2006 % Change
-------------------------------------------------------------------------
FINANCIAL ($000 except
per share amounts)
Revenues, net
of royalties 93,266 61,239 52 159,189 64,874 145
Cash flow from
operations(1) 16,876 9,499 78 27,857 11,224 148
Per share,
basic(1) 0.09 0.05 80 0.14 0.07 100
Per share,
diluted(1) 0.08 0.05 60 0.14 0.06 133
Net earnings (loss)
for the period 22,228 (2,419) 1,019 27,212 (3,085) 982
Per share, basic 0.11 (0.01) 1,200 0.14 (0.02) 800
Per share, diluted 0.11 (0.01) 1,200 0.14 (0.02) 800
Capital expenditures
and acquisitions 93,223 34,280 172 203,104 335,116 (39)
Cash on hand 25,375 7,505 238
Working capital
(deficit) 36,320 (42,483) 185
Long term debt 272,559 - -
Shareholders' equity 417,793 340,639 23
Total assets 821,927 492,859 67
OPERATING
Daily production
/sales volumes
Crude oil - bbl/d 731 1,026 (29) 817 858 (5)
Natural gas - mcf/d 9,017 15,172 (41) 9,340 8,921 5
Barrels of oil
equivalent
- boe/d(2) 2,234 3,554 (37) 2,374 2,345 1
Product pricing
Oil - $/bbl 49.79 61.45 (19) 49.42 53.26 (7)
Natural gas - $/mcf 7.02 5.66 24 7.40 5.76 28
Barrels of oil
equivalent
- $/boe(2) 44.63 41.88 7 46.13 41.39 11
Common shares
outstanding (000)
Weighted average
Basic 198,360 191,672 3 198,240 173,015 15
Diluted 209,088 198,931 5 204,762 180,416 14
End of period
Issued 198,834 191,924 4
Fully diluted 236,811 207,551 14
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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.
Connacher Oil and Gas had a wonderful second quarter and first half of
2007. The events of the quarter were dominated by continued excellent progress
in our construction of facilities at Great Divide Pod One, within timetable
and close to budget. Our accomplishments in this regard, especially for a
smaller company, are considerable.
While we did experience modest cost overruns, they were both manageable
and comprehensible against the backdrop of incredible inflationary pressure in
this space. We will have completed the plant and facility and site
construction within our allotted 300 days, an achievement of which we can be
justifiably proud, especially with the pressures of competition, weather in
that we built through a fairly cold winter and the original delays and site
construction challenges we faced.
Also, our extensive and successful 81 well core hole drilling program
this past winter on our main lease block at Great Divide resulted in a marked
expansion of our reserve and resource base and supported our application to
proceed with a second oil sands plant to also produce 10,000 bbl/d of bitumen
at Algar. The proposed plant site is approximately five miles east of the Pod
One plant, across Highway 63. Assuming an approximate 12 month review period
by the regulators and for consultation with interested stakeholders, Connacher
hopes to be able to proceed with building its second plant sometime during the
first half of 2008 with a view to completion by early 2009.
The company is also optimistic about its ability to further identify and
upgrade other accumulations on its 100 percent-owned acreage in the Divide
region to commercial status and in the fullness of time, over the next seven
years or so, would anticipate moving towards overall production in excess of
50,000 bbl/d in the region. This outlook is buoyed by the continuing
identification of many new leads and prospects on our main lease block arising
from the winter 2007 3D seismic program. Connacher will continue its cycle of
shooting extensive 3D seismic over its undrilled or unevaluated acreage,
followed by an active core hole program and then, with these results in hand,
continued reserve and resource expansion on a consistent and regular basis.
Already we are anticipating a 120-130 well core hole drilling program in the
winter of 2008, primarily on our main lease block. New seismic in 2008 will
focus on our unevaluated lands to set up drilling the following winter.
Unlike many other companies who are drilling core holes in a more
"exploratory" manner, in order to establish broad based resource estimates for
prospective company sales, Connacher uses core hole drilling for defining
exploitable reserves which can be booked and converted to production in an
expeditious manner. We have moved from initial ownership to production in the
shortest timeframe of any other producer in the oil sands. Our compact and
coordinated approach will serve us well going forward as we become a more
meaningful production company.
Connacher's reserve and resource base expanded dramatically compared to
year end 2006. On July 10, 2007 we issued a press release detailing the
results of an updated independent reserve report ("June 2007 Report"),
prepared by GLJ Petroleum Consultants ("GLJ"), of Calgary, Alberta. The June
2007 Report had an effective date of June 30, 2007 and detailed estimates of
the company's bitumen and conventional reserves and resources for 1P, 2P and
3P reserves and contingent and prospective resources for bitumen and 1P and 2P
reserves for conventional resources. The company's reserve and resource base
showed considerable expansion, as did the GLJ estimates of future net revenue
and the present value thereof, calculated after deduction of estimated capital
expenditures, royalties and operating costs but before corporate general and
administrative expenses ("G&A"), finance charges and income tax. This expanded
reserve and resource base and the value of Connacher's future net revenue
provides a solid underpinning for the company's net asset value and
creditworthiness, which was reaffirmed by an improvement in the ratings
assigned by Standard and Poor's to the company's outstanding debt instruments.
Other developments of consequence during the period included the exercise
by Connacher of its Petrolifera Petroleum Limited initial warrants to maintain
the company's equity stake in this highly successful company at the 26 percent
level. Also, during the reporting period Connacher was able to further
strengthen its financial condition with the successful placement for resale of
$100 million of 4.75 percent senior subordinated unsecured convertible
debentures, on a bought deal basis with a syndicate of investment banks,
headed by Canada's largest investment dealer. This expression of support and
increased sponsorship reflects favorably on the company's progress as the
transaction was also fully supported by the company's previous banking
syndicate.
Also, Connacher's $50 million revolving reserve-backed loan facility,
secured by Connacher's conventional reserve base, was renewed during the
period, based on the company's successful 2007 drilling program and despite
the erosion of natural gas prices which adversely affected loan values for the
industry. The facility was undrawn as at quarter end.
Connacher's financial and operating results for the second quarter and
first half of 2007 are discussed in greater detail in the MD&A which comprises
a portion of this Interim Report. However, some items of note should be
recognized. Our refinery in Montana had an exceptional second quarter and
first half 2007 with a significant expansion in refining netbacks, especially
in the second quarter. Our cash flow from operations continued to grow nicely,
reaching $27.9 million for the first half 2007 and increasing by about
78 percent over the first quarter 2007 at $16 million. This represents an
increase of 148 percent over the first half of 2006 and 78 percent for the
second quarter. Cash flow per share (weighted average) was 80 percent higher
in the first half of 2007 compared to 2006, performance achieved during a
period when our focus was on our considerable efforts at Pod One.
Earnings showed an even better relative performance, reaching
$27.2 million for the first half of 2007, compared to a $3.1 million loss last
year. While the results were influenced markedly by foreign exchange gains,
which arose from the strength of the Canadian dollar, related to our
US$-denominated indebtedness, the strong dollar also adversely influences
Canadian dollar pricing for crude oil and natural gas. Second quarter 2007
earnings were $22.2 million ($0.11 per share).
All resolutions submitted to shareholders for approval at the company's
Annual and Special Meeting held on May 10, 2007 were approved by shareholders.
We have also been very successful in attracting new expertise and talent to
the company with our hiring program at head office and at Great Divide as we
plan for our exciting future. We welcomed one new officer and numerous new
employees to the company during the second quarter reporting period, which is
a positive reflection on Connacher's reputation as a dynamic and growing
business.
Following our plant commissioning (formal ceremony on August 10, 2007 and
then the balance of the commissioning process until mid-September) we will
begin injecting steam into the fifteen SAGD well pairs which are onsite at
Great Divide Pod One. This process will be carried out with close monitoring
for 90 days, after which production will commence from Pod One and will be
ramped up thereafter towards our licensed volume of 10,000 bbl/d. We will keep
our shareholders informed of our progress. Check our website at
www.connacheroil.com for pictures and periodic updates as new information
becomes available.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is dated as of August 9, 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 and six
months ended June 30, 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 six months ended June 30, 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 ("PNG") PRODUCTION, PRICING AND REVENUE
-------------------------------------------------------------------------
Three months ended June 30 Six months ended June 30
-------------------------------------------------------------------------
2007 2006 % Change 2007 2006 % Change
-------------------------------------------------------------------------
Daily production
/sales volumes
-------------------------------------------------------------------------
Crude oil - bbl/d 731 1,026 (29) 817 858 (5)
-------------------------------------------------------------------------
Natural gas - mcf/d 9,017 15,172 (41) 9,340 8,921 5
-------------------------------------------------------------------------
Combined - boe/d 2,234 3,554 (37) 2,374 2,345 1
-------------------------------------------------------------------------
Product pricing ($)
Crude oil - per bbl 49.79 61.45 (19) 49.42 53.26 (7)
-------------------------------------------------------------------------
Natural gas
- per mcf 7.02 5.66 24 7.40 5.76 28
-------------------------------------------------------------------------
Combined - per boe 44.63 41.88 7 46.13 41.39 12
-------------------------------------------------------------------------
Revenue ($000)
-------------------------------------------------------------------------
PNG revenue - gross 9,070 13,546 (33) 19,817 17,567 13
-------------------------------------------------------------------------
Royalties (657) (3,375) (81) (3,197) (4,185) (24)
-------------------------------------------------------------------------
PNG revenue - net 8,413 10,171 (17) 16,620 13,382 24
-------------------------------------------------------------------------
In the second quarter of 2007, net PNG revenues were down 17 percent to
$8.4 million from $10.2 million in 2006. This was primarily attributable to a
41 percent decrease in natural gas sales volumes as no new wells, reserves and
behind pipe production tested at over 1,000 boe/d (all natural gas) can be
placed onstream until the winter first quarter of 2008 due to limited access,
and a 29 percent decrease in crude oil sales volumes. Although world oil
selling prices were down approximately eight percent from the second quarter
of 2006, the company's average crude oil selling price decreased by 19 percent
to $49.79 per barrel due to the impact of crude quality differentials on
pricing and the effect of the strengthening Canadian dollar on the prices
received by the company. The company's natural gas sales prices increased
24 percent in 2007 as a result of achieving better industry market pricing for
our 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 of
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 notional 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 important during a period of rapid growth
with significant capital expenditures. At June 30, 2007 the fair value of this
collar was an asset of $282,000, recorded in accounts receivable on the
consolidated balance sheet and the gain has been included in PNG revenue.
ROYALTIES ON PNG SALES
-------------------------------------------------------------------------
2007 2006
For the three months ended June 30 -----------------------------------
($000 except per boe) Total Per boe Total Per boe
-------------------------------------------------------------------------
Royalties $657 $3.23 $3,375 $10.43
-------------------------------------------------------------------------
As a percentage of PNG revenue 7.2% 25.0%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007 2006
For the six months ended June 30 -----------------------------------
($000 except per boe) Total Per boe Total Per boe
-------------------------------------------------------------------------
Royalties $3,197 $7.44 $4,185 $ 9.86
-------------------------------------------------------------------------
As a percentage of PNG revenue 16.1% 24.0%
-------------------------------------------------------------------------
Royalties represent charges against production or revenue by governments
and landowners. Royalties in the second quarter of 2007 were $657,000
($3.23 per boe, or seven percent of petroleum and natural gas revenue)
compared to $3.4 million in 2006 ($10.43 per boe, or 25 percent of petroleum
and natural gas revenue). The decrease, which was substantially non-recurring,
occurred primarily due to gas cost allowance credits received in the second
quarter of 2007 relating to prior year royalties. 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.
PNG OPERATING EXPENSES AND NETBACKS
-------------------------------------------------------------------------
PNG Netbacks(1)
For the three months
ended June 30 2007 2006 % Change
-------------------------------------------------------------------------
($000 except
per boe) Total Per boe Total Per boe Total Per boe
-------------------------------------------------------------------------
Average daily
production (boe/d) 2,234 3,554 (37)
Gross PNG revenue $ 9,070 $ 44.63 $13,546 $ 41.88 (33) 7
Royalties (657) (3.23) (3,375) (10.43) (81) (70)
-------------------------------------------------------------------------
Net PNG revenue 8,413 41.40 10,171 31.45 (17) 32
Operating costs (2,660) (13.08) (2,468) (7.63) 8 71
-------------------------------------------------------------------------
PNG netback $ 5,753 $ 28.32 $ 7,703 $ 23.82 25 19
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the six months
ended June 30 2007 2006 % Change
-------------------------------------------------------------------------
($000 except
per boe) Total Per boe Total Per boe Total Per boe
-------------------------------------------------------------------------
Average daily
production (boe/d) 2,374 2,345 1
Gross PNG revenue $19,817 $ 46.13 $17,567 $ 41.39 13 11
Royalties (3,197) (7.44) (4,185) (9.86) (24) (25)
-------------------------------------------------------------------------
Net PNG revenue 16,620 38.69 13,382 31.53 24 23
Operating costs (4,592) (10.69) (3,300) (7.77) 39 38
-------------------------------------------------------------------------
PNG netback $12,028 $ 28.00 $10,082 $ 23.76 19 18
-------------------------------------------------------------------------
(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 second quarter of 2007 operating costs of $2.7 million were eight
percent higher than in the same prior period, and on a per unit basis,
increased by 71 percent to $13.08 per boe reflecting the higher cost
environment in 2007 in addition to more well workovers completed in 2007 and
higher power costs. However, higher product prices and lower royalties
resulted in higher operating netbacks in 2007.
Reconciliation of PNG Netback to Net Earnings(1)
-------------------------------------------------------------------------
For the six months ended June 30 2007 2006
-------------------------------------------------------------------------
($000, except per unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
PNG netback as above $12,028 $28.00 $10,082 $23.76
-------------------------------------------------------------------------
Interest income 345 0.80 525 1.24
-------------------------------------------------------------------------
Refining margin - net 29,346 68.29 3,988 9.40
-------------------------------------------------------------------------
General and administrative (5,248) (12.21) (2,299) (5.42)
-------------------------------------------------------------------------
Stock-based compensation (3,279) (7.63) (5,194) (12.24)
-------------------------------------------------------------------------
Finance charges (1,710) (3.98) (3,239) (7.63)
-------------------------------------------------------------------------
Foreign exchange (loss) gain 16,188 37.67 (38) (0.09)
-------------------------------------------------------------------------
Depletion, depreciation
and amortization (14,721) (34.25) (12,890) (30.37)
-------------------------------------------------------------------------
Income taxes (12,747) (29.67) 3,339 7.87
-------------------------------------------------------------------------
Equity interest in Petrolifera
earnings and dilution gain 7,010 16.31 2,641 6.22
-------------------------------------------------------------------------
Net earnings (loss) $27,212 $63.33 $(3,085) $(7.26)
-------------------------------------------------------------------------
(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 three months ended Crude oil Natural gas
June 30, 2007 -----------------------------------
($000, except per unit amounts) Total Per bbl Total Per mcf
-----------------------------------
-------------------------------------------------------------------------
Average daily production 731 bbl/d 9,017 mcf/d
Revenue $ 3,311 $ 49.79 $ 5,759 $ 7.02
Royalties (828) (12.45) 171 0.21
Operating costs (808) (12.15) (1,852) (2.26)
-------------------------------------------------------------------------
PNG Netback $ 1,675 $ 25.19 $ 4,078 $ 4.97
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the three months ended Crude oil Natural gas
June 30, 2006 -----------------------------------
Total Per bbl Total Per mcf
-------------------------------------------------------------------------
($000s, except per unit amounts)
-------------------------------------------------------------------------
Average daily production 1,026 bbl/d 15,172 mcf/d
Revenue $ 5,735 $ 61.45 $ 7,811 $ 5.66
Royalties (1,267) (13.57) (2,108) (1.53)
Operating costs (870) (8.78) (1,648) (1.19)
-------------------------------------------------------------------------
PNG Netback $ 3,648 $ 39.10 $ 4,055 $ 2.94
-------------------------------------------------------------------------
For the six months ended June 30, 2007
-------------------------------------------------------------------------
Crude oil Natural gas
2007 -----------------------------------
($000, except per unit amounts) Total Per bbl Total Per mcf
-----------------------------------
-------------------------------------------------------------------------
Average daily production 817 bbl/d 9,340 mcf/d
Revenue $ 7,308 $ 49.42 $12,509 $ 7.40
Royalties (1,767) (11.95) (1,430) (0.85)
Operating costs (1,684) (11.39) (2,908) (1.72)
-------------------------------------------------------------------------
PNG Netback $ 3,857 $ 26.08 $ 8,171 $ 4.83
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the six months ended Crude oil Natural gas
June 30, 2006 -----------------------------------
Total Per bbl Total Per mcf
-------------------------------------------------------------------------
($000, except per unit amounts)
-------------------------------------------------------------------------
Average daily production 858 bbl/d 8,921 mcf/d
Revenue $ 8,273 $ 53.26 $ 9,294 $ 5.76
Royalties (1,713) (11.03) (2,472) (1.53)
Operating costs (1,349) (8.68) (1,951) (1.21)
-------------------------------------------------------------------------
PNG Netback $ 5,211 $ 33.55 $ 4,871 $ 3.02
-------------------------------------------------------------------------
REFINING REVENUES AND MARGINS
The quarterly operating results of the Montana refinery are summarized
below.
Refining Operations and Sales
The Montana refinery is subject to a number of seasonal factors which may
cause product sales to vary throughout the year. The refinery's primary
asphalt market is paving for road construction which is predominantly a summer
demand. Consequently, process and volumes for our asphalt tend to be higher in
the summer and lower in the colder seasons. 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 the 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.
The Montana refinery achieved record performance during the second
quarter 2007 due to higher product prices and refining margins. Refining sales
revenues were $84.6 million compared to $57.6 million in the first quarter
2007 and $51.0 million in the second quarter of 2006. Sales revenues increased
due to higher product prices and higher seasonal sales of asphalt.
Crude oil and operating costs were also up, rising to $66.5 million in
the quarter 2007 compared to $46.4 million in the first quarter 2007 and
$47 million in the same period last year. Refinery margins increased to
$18.1 million (21.4%) compared to $11.2 million (19.4%) in the first quarter
2007 and $4.0 million (7.8%) in the second quarter of 2006.
In the first six months of 2007, the refinery ran at 99% of capacity and
there was no downtime. During the second quarter the company sanctioned its
ultralow sulphur diesel project to allow the company to produce ultraclean
fuels by late 2008. Vendor selection and detailed engineering design is
currently underway. The company has also initiated a project to assess a
potential expansion of the Montana refinery. The project is currently in the
conceptual engineering stage.
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
Refinery throughput 2007 2006 2007 2006(5)
-------------------------------------------------------------------------
Crude charged (bbl/d)(1) 9,244 6,864 9,432 6,864
-------------------------------------------------------------------------
Refinery production (bbl/d)(2) 10,085 6,932 10,358 6,932
-------------------------------------------------------------------------
Sales of produced refined products
(bbl/d) 9,753 6,266 8,771 6,266
-------------------------------------------------------------------------
Sales of refined products (bbl/d)(3) 10,735 7,384 9,501 7,384
-------------------------------------------------------------------------
Refinery utilization (%)(4) 97.3% 82.7% 99.3% 82.7%
-------------------------------------------------------------------------
(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.
(5) From the date of acquisition on March 31, 2006.
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
2007 2006 2007 2006
-------------------------------------------------------------------------
Feedstocks - three months ended
-------------------------------------------------------------------------
Sour crude oil (%) 93% 98% 93% 98%
-------------------------------------------------------------------------
Other feedstocks and blends (%) 7% 2% 7% 2%
-------------------------------------------------------------------------
Total 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Revenues and Margins
-------------------------------------------------------------------------
Refining sales revenue ($000s) 84,628 50,967 142,224 50,967
-------------------------------------------------------------------------
Refining - crude oil and operating
costs ($000s) 66,480 46,979 112,878 46,979
-------------------------------------------------------------------------
Refining margin ($000s) 18,148 3,988 29,346 3,988
-------------------------------------------------------------------------
Refining margin (%) 21.4% 7.8% 20.6% 7.8%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Sales of Produced Refined Products (Volume %)
-------------------------------------------------------------------------
Gasolines (%) 40% 27% 45% 27%
-------------------------------------------------------------------------
Diesel fuels (%) 18% 15% 22% 15%
-------------------------------------------------------------------------
Jet fuels (%) 5% 3% 5% 3%
-------------------------------------------------------------------------
Asphalt (%) 33% 50% 24% 50%
-------------------------------------------------------------------------
LPG and other (%) 4% 5% 4% 5%
-------------------------------------------------------------------------
Total 100% 100% 100% 100%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Averages per Barrel of Refined Product Sold
-------------------------------------------------------------------------
Refining sales revenue $ 86.63 $ 89.38 $ 82.70 $ 89.38
-------------------------------------------------------------------------
Less: refining - crude oil purchases
and operating costs 68.05 82.39 65.64 82.39
-------------------------------------------------------------------------
Refining margin $ 18.58 $ 6.99 $ 17.06 $ 6.99
-------------------------------------------------------------------------
INTEREST AND OTHER INCOME
In the second quarter of 2007, the company earned interest of $225,000
(second quarter, 2006 - $101,000) on excess funds invested in secure
short-term investments.
GENERAL AND ADMINISTRATIVE EXPENSES
In the second quarter of 2007, general and administrative ("G&A")
expenses were $1.7 million compared to $1.3 million in the second quarter of
2006, an increase of 24 percent, reflecting increased costs associated with
the company's growth. On a per unit basis, G&A was $8.18 per boe sold,
reflecting the project nature of the company's main activity, and is expected
to be significantly reduced when bitumen production from Pod One commences and
is booked. G&A of $1.1 million was capitalized in the first six months of 2007
(2006 - $99,000), primarily reflecting costs incurred respecting the oil sands
development in the pre-production stage.
Non-cash stock-based compensation costs of $875,000 were recorded in the
second quarter of 2007 (June 30, 2006 - $6.5 million). These charges reflect
the fair value of all stock options granted and vested in the period. Of this
amount, $333,000 was expensed (2006 - $4.8 million) and $542,000 was
capitalized (2006 - $1.7 million). Charges for the reporting periods are lower
in 2007 due to either the timing of awards or lower award volumes in 2007.
FINANCE CHARGES AND FOREIGN EXCHANGE
Financing charges in the second quarter of 2007 of $1.3 million (year to
date - $1.7 million) comprise interest paid on funds drawn on the company's
lines of credit, interest accrued on the Convertible Debentures and accretion
booked on the Convertible Debentures. Finance charges in the second quarter of
2006 of $3.2 million (first six months of 2006 - $3.3 million) comprise
interest on the company's lines of credit, interest on the US $51 million
bridge loan then outstanding and the amortization of deferred financing costs
related to the US $51 million bridge loan facility placed in 2006. Interest on
the oil sands term loan is capitalized during the pre-operating phase.
An unrealized foreign exchange gain of $14.5 million was recorded in the
second 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 significantly 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, the
translation of the US$180 million oil sands term loan and the translation of
the Montana refinery financial results. 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 second quarter of 2007 was $7.4 million, a 30 percent decrease
from last year due to decreased production volumes and increased proved
conventional reserves. Conventional oil and gas depletion equates to
$34.25 per boe of production on a year-to-date basis compared to $28.50 per
boe last year. Depletion of Pod One's oil sands capital costs will commence
when that project attains commercial production.
Capital costs of $322 million (June 30, 2006 - $64 million) related to
the Great Divide oil sands project, which is in the pre-production stage, and
undeveloped land acquisition costs of $17 million (2006 - $10 million) were
excluded from the depletion calculation, while future development costs of
$15 million (2006 - $2 million) for proved undeveloped reserves were included
in the depletion calculation.
Included in DD&A is an accretion charge of $433,000 (June 30, 2006 -
$130,000) 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 $13.1 million to the estimated total
undiscounted liability of $42 million over the remaining economic life of the
company's oil and gas properties.
INCOME TAXES
The income tax provision of $12.7 million in the first six months of 2007
includes a current income tax provision of $7.5 million, principally related
to US refinery operations and a future income tax provision of $5.3 million
relating to both Canadian and US operations. The income tax recovery of
$3.3 million for the first six months of 2006 was due primarily to enacted
federal and provincial tax rate reductions.
At June 30, 2007 the company had approximately $28 million of non-capital
losses which do not expire before 2009, $416 million of deductible resource
pools and $21 million of deductible financing costs.
EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA") AND
DILUTION GAIN
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 six months of 2007 was $5.1 million
(June 30, 2006 - $2.6 million).
In May 2007, the company exercised its right to purchase 1.7 million
additional common shares in Petrolifera for total consideration of
$5.1 million. As a result, the company maintained its 26 percent equity
interest, as other Petrolifera shareholders similarly exercised their right to
purchase additional common shares in Petrolifera on identical terms. As a
consequence of this investment, the company's carrying value of its
Petrolifera investment holding increased to cause a dilution gain of $1.9
million.
NET EARNINGS
In the first six months of 2007, the company reported earnings of
$27.2 million ($0.14 per basic and diluted share outstanding) compared to a
loss of $3.1 million or $0.02 loss per basic and diluted share for the first
six months of 2006. In 2007, the refinery contributed significantly to these
results, as did the recorded foreign exchange gains.
SECURITIES OUTSTANDING
For the first six months of 2007, the weighted average number of common
shares outstanding was 198,240,426 (2006 - 173,015,395) and the weighted
average number of diluted shares outstanding, as calculated by the treasury
stock method, was 204,762,395 (2006 - 180,415,669).
As at August 8, 2007, the company had the following securities issued and
outstanding:
- 198,953,923 common shares;
- 17,939,711 share purchase options;
- 217,950 deferred share units ("DSUs") under the share award plan; and
- 20,010,000 common shares issuable upon conversion of the $100,050,000
convertible debentures
Details of the exercise provisions and terms of the outstanding options,
DSUs and convertible debentures are noted in the consolidated financial
statements, included in this interim report.
LIQUIDITY AND CAPITAL RE
SOURCES
On May 25, 2007 Connacher issued senior unsecured subordinated
convertible debentures with a face value of $100,050,000. The debentures
mature June 30, 2012 unless converted prior to that date and bear interest at
an annual rate of 4.75 percent payable semiannually on June 30 and
December 31. The debentures are convertible at any time into common shares at
the option of the holder at a conversion price of $5 per share.
The debentures are redeemable or after June 30, 2010 by the company, in
whole or in part at a redemption price equal to 100 percent of the principal
amount of the debentures to be redeemed plus accrued and unpaid interest
provided that the market price of the company's common shares is at least
120 percent of the conversion price of the debentures.
The conversion feature of the debentures has been accounted for as a
separate component of equity in the amount of $16,823,000. The remainder of
the net proceeds of the debentures of $79,243,000 has been recorded as
long-term debt, which will be accreted up to the face value of $100,050,000
over the five-year term of the debentures. Accretion and interest paid are
recorded as finance charges on the consolidated statement of operations. If
the debentures are converted to common shares, the value of the conversion
feature will be reclassified to share capital along with the principal amounts
converted.
Proceeds of the financing were utilized as follows:
-------------------------------------------------------------------------
As stated As
at the time actually
of financing applied
-------------------------------------------------------------------------
($000s)
-------------------------------------------------------------------------
Gross proceeds $ 100,050 $ 100,050
Underwriters' commissions and issue cost 3,252 3,984
-------------------------------------------------------------------------
Net proceeds $ 96,798 $ 96,066
-------------------------------------------------------------------------
The net proceeds were used to fund the company's ongoing capital
expenditure program in respect of the development of its oil sands projects,
its conventional capital program, for operating expenses, and to repay
$52.5 million of the company's conventional oil and gas operating line of
credit, which had been drawn to temporarily fund some of the aforementioned
capital and operating expenditures.
In the second quarter of 2007, the company also renewed its revolving
conventional oil and gas operating line of credit for one year for a limit of
$50 million. None of this amount was drawn at June 30, 2007.
At June 30, 2007, the company had working capital of $36.3 million,
including $21 million of cash and $4.5 million of segregated cash dedicated to
funding the remaining costs of completing the Pod One oil sands project, no
short-term debt, an unused $50 million reserve-backed revolving line of
credit.
In the first half of 2007, cash flow was $27.8 million ($0.14 per basic
and diluted share), 148 percent higher than the $11.2 million reported
($0.07 per basic and $0.06 diluted share) for the first half of 2006. A
significant portion of this was contributed by the refinery.
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.
As the company's oil sands term loan is denominated in US dollars, there
is a foreign exchange risk associated with its repayment using Canadian
currency. 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 company has entered into an interest rate swap to mitigate
some of the interest rate volatility associated with the variable interest
rate inherent in the oil sands term loan.
The company also entered into a natural gas costless collar 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.
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.
Reconciliation of net earnings to cash flow from operations before
working capital changes:
-------------------------------------------------------------------------
Three months ended Six months ended
June 30 June 30
2007 2006 2007 2006
-------------------------------------------------------------------------
($000s)
-------------------------------------------------------------------------
Net earnings (loss) $22,228 $(2,419) $27,212 $(3,085)
Items not involving cash:
Depletion, depreciation
and accretion 7,363 10,013 14,721 12,890
Stock-based compensation 333 4,800 3,279 5,194
Financing charges 324 2,300 324 2,307
Future employee benefits 122 124 252 124
Future income tax provision
(recovery) 4,102 (3,186) 5,267 (3,573)
Foreign exchange (gain) loss (14,486) 31 (16,188) 38
Lease inducement amortization - (15) - (30)
Dilution (gain) loss (1,896) 51 (1,896) (52)
Equity interest in Petrolifera
earnings (1,214) (2,200) (5,114) (2,589)
-------------------------------------------------------------------------
Cash flow from operations before
working capital changes $16,876 $ 9,499 $27,857 $11,224
-------------------------------------------------------------------------
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.
CAPITAL EXPENDITURES AND FINANCING ACTIVITIES
Capital expenditures totaled $93.2 million in the second quarter of 2007
and $203.1 million year-to-date (second quarter 2006 - $34.3 million; first
half of 2006 - $335.1 million). A breakdown of these expenditures follows:
-------------------------------------------------------------------------
Six months ended June 30
($000) 2007 2006
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Acquisition of Luke Energy Ltd. $- $205,000
Acquisition of the Montana refinery assets - 67,000
Oil sands expenditures 166,523 52,096
Conventional oil and gas expenditures 30,737 10,763
Refinery expenditures 5,844 257
-------------------------------------------------------------------------
$203,104 $335,116
-------------------------------------------------------------------------
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 six months of 2007, 75 exploratory core
holes were drilled. In the first half 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, 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 and 100% interest in its oil sands 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
95,000 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
$277 million of expenditures have been incurred to June 30, 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 $300 million, prior
to the commencement of bitumen production in the latter part of 2007. The
remaining costs will be funded with cash on hand and available lines of
credit.
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 the Consolidated Statement of Other Comprehensive Income, has been
introduced which identifies certain gains and losses, including 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 at fair values.
CONVERTIBLE DEBENTURES
The convertible debentures have been recorded as a compound financial
instrument in accordance with Section 3861 of the CICA Handbook. The fair
value of the liability component has been determined at the date of issue
based on the company's incremental borrowing rate for debt with similar terms.
The amount of the equity component has been determined as a residual after
deducting the amount of the liability component from the face value of the
issue.
DEFERRED SHARE AWARD PLAN
Obligations for payments in cash or common shares under the company's
deferred share award plan for non-employee directors are accrued as
compensation expense over the vesting period. Fluctuations in the price of the
company's common shares change the accrued compensation expense and are
recognized when they occur.
BUSINESS RISKS
Connacher is exposed to certain risks and uncertainties inherent in the
oil and gas and refining businesses. Furthermore, 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 is exposed to other risks including currency fluctuations,
political risk, price controls and varying forms of fiscal regimes or changes
thereto which may impair that investee'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 refinery, 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. The refinery'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.
The refinery'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, the refinery 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 the refinery. 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. It is anticipated this
risk will be substantially mitigated by the production and sale of natural gas
from the company's gas properties at Marten Creek acquired with the purchase
of Luke Energy Ltd.
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. Long-life reserves such as the oil
sands now owned by the company may facilitate greater utilization of medium to
long-term debt to finance development projects. 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.
Long-life reserves such as the oil sands now owned by the company may
facilitate greater utilization of medium to long-term debt to finance
development projects.
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 2006
-------------------------------------------------------------------------
Three Months Ended Sept 30 Dec 31 Mar 31 Jun 30
-------------------------------------------------------------------------
Financial Highlights ($000 except
per share amounts) - Unaudited
Revenue net of royalties 3,222 2,978 3,635 61,239
Cash flow from operations before
working capital changes(1) 1,978 1,238 1,725 9,499
Basic, per share(1) 0.02 0.01 0.01 0.05
Diluted, per share(1) 0.02 0.01 0.01 0.05
Net earnings (loss) (1,034) 582 (666) (2,419)
Basic and diluted per share (0.01) - - (0.01)
Capital expenditures 2,870 2,241 300,836 34,280
Proceeds on disposal of PNG properties - - - -
Cash on hand 67,708 75,511 - 7,505
Working capital surplus (deficiency) 67,440 75,427 (11,061) (42,483)
Long term debt - - - -
Shareholders' equity 113,081 129,108 337,584 340,639
Operating Highlights
Daily production/sales volumes
Natural gas - mcf/d 497 86 2,600 15,172
Crude oil - bbl/d 808 775 689 1,026
Equivalent - boe/d(2) 891 789 1,122 3,554
Product pricing
Crude oil - $/bbl 53.40 41.54 40.93 61.45
-----------------------------------
Natural gas - $/mcf 1.88 7.55 6.34 5.66
Selected Highlights - $/boe(2)
Weighted average sales price 49.48 41.61 39.83 41.88
Royalties 11.73 7.76 8.02 10.43
Operating costs 7.69 8.90 8.24 7.63
PNG netback(4) 30.06 24.95 23.57 23.82
Common Share Information
Shares outstanding at end
of period (000) 134,236 139,940 191,257 191,924
Basic (000) 103,851 136,071 154,152 191,672
Diluted (000) 106,397 142,507 160,574 198,931
Volume traded during quarter (000) 180,848 100,246 148,184 80,347
Common share price ($)
High 2.69 4.20 6.07 5.05
Low 0.76 1.09 3.47 3.10
Close (end of period) 2.54 3.84 4.95 4.30
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2006 2007
-------------------------------------------------------------------------
Three Months Ended Sept 30 Dec 31 Mar 31 Jun 30
-------------------------------------------------------------------------
Financial Highlights ($000 except
per share amounts) - Unaudited
Revenue net of royalties 103,110 76,700 65,923 93,266
Cash flow from operations before
working capital changes(1) 14,957 14,015 10,980 16,876
Basic, per share(1) 0.08 0.08 0.06 0.09
Diluted, per share(1) 0.08 0.07 0.05 0.08
Net earnings (loss) 6,771 3,267 4,984 22,228
Basic and diluted per share 0.03 0.02 0.03 0.11
Capital expenditures 41,449 74,960 109,881 93,223
Proceeds on disposal of PNG properties - 10,000 - -
Cash on hand 14,450 142,391 66,209 25,375
Working capital surplus (deficiency) (39,942) 118,626 24,027 36,320
Long term debt - 209,754 207,828 272,559
Shareholders' equity 378,730 385,398 384,593 417,793
Operating Highlights
Daily production/sales volumes
Natural gas - mcf/d 12,711 11,291 9,665 9,017
Crude oil - bbl/d 1,059 1,139 905 731
Equivalent - boe/d(2) 3,177 3,021 2,515 2,234
Product pricing
Crude oil - $/bbl 62.53 46.65 49.09 49.79
-----------------------------------
Natural gas - $/mcf 5.33 6.57 7.76 7.02
Selected Highlights - $/boe(2)
Weighted average sales price 42.16 42.15 47.48 44.63
Royalties 10.72 9.00 11.22 3.23
Operating costs 7.99 9.27 8.54 13.08
PNG netback(4) 23.45 23.88 27.72 28.32
Common Share Information
Shares outstanding at end
of period (000) 197,878 197,894 198,218 198,834
Basic (000) 193,587 193,884 198,119 198,360
Diluted (000) 200,572 204,028 200,008 209,088
Volume traded during quarter (000) 48,849 46,444 55,292 61,162
Common share price ($)
High 4.55 4.43 4.13 4.43
Low 3.09 3.17 3.07 3.07
Close (end of period) 3.60 3.49 3.86 3.69
-------------------------------------------------------------------------
(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) June 30, December 31,
2007 2006
-------------------------------------------------------------------------
ASSETS
CURRENT
Cash and cash equivalents $20,889 $19,603
Restricted cash (Note 11 (c)) 4,486 122,788
Accounts receivable 43,488 30,956
Refinery inventories (Note 4) 37,176 24,437
Prepaid expenses 2,171 1,525
Income taxes recoverable 3,942 -
Due from Petrolifera - 32
-------------------------------------------------------------------------
112,152 199,341
Property and equipment 569,532 384,311
Goodwill 103,676 103,676
Deferred costs 2,817 4,005
Investment in Petrolifera 33,750 21,597
-------------------------------------------------------------------------
$821,927 $712,930
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
CURRENT
Accounts payable and accrued liabilities $69,400 $57,571
Income taxes payable - 3,644
Revolving line of credit 6,392 19,500
Due to Petrolifera 40 -
-------------------------------------------------------------------------
75,832 80,715
Asset retirement obligations (Note 5) 13,074 7,322
Employee future benefits (Note 11(d)) 591 388
Long term debt (Note 7) 272,559 209,754
Future income taxes 42,078 29,353
-------------------------------------------------------------------------
404,134 327,532
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital and contributed surplus (Note 8) 389,230 376,500
Accumulated other comprehensive loss (Note 3) (7,677) (130)
Retained earnings 36,240 9,028
-------------------------------------------------------------------------
417,793 385,398
-------------------------------------------------------------------------
$821,927 $712,930
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF OPERATIONS
AND RETAINED EARNINGS
Connacher Oil and Gas Limited
(Unaudited)
-------------------------------------------------------------------------
Three Months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000, except per share amounts) 2007 2006 2007 2006
-------------------------------------------------------------------------
REVENUE
Petroleum and natural gas revenue,
net of royalties $8,413 $10,171 $16,620 $13,382
Refining and marketing sales 84,628 50,967 142,224 50,967
Interest and other income 225 101 345 525
-------------------------------------------------------------------------
93,266 61,239 159,189 64,874
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EXPENSES
Petroleum and natural gas
operating costs 2,660 2,468 4,592 3,300
Refining - crude oil purchases
and operating costs 66,480 46,979 112,878 46,979
General and administrative 1,663 1,343 5,248 2,299
Stock-based compensation (Note 8) 333 4,800 3,279 5,194
Finance charges 1,264 3,155 1,710 3,239
Foreign exchange loss (gain) (14,486) 31 (16,188) 38
Depletion, depreciation
and accretion 7,363 10,013 14,721 12,890
-------------------------------------------------------------------------
65,277 68,789 126,240 73,939
-------------------------------------------------------------------------
Earnings (loss) before income
taxes and other items 27,989 (7,550) 32,949 (9,065)
Current income tax provision 4,769 204 7,480 234
Future income tax provision
(recovery) 4,102 (3,186) 5,267 (3,573)
-------------------------------------------------------------------------
8,871 (2,982) 12,747 (3,339)
-------------------------------------------------------------------------
Earnings (loss) before other items 19,118 (4,568) 20,202 (5,726)
Equity interest in Petrolifera
earnings 1,214 2,200 5,114 2,589
Dilution gain (loss) (Note 6) 1,896 (51) 1,896 52
-------------------------------------------------------------------------
NET EARNINGS (LOSS) 22,228 (2,419) 27,212 (3,085)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS,
BEGINNING OF PERIOD 14,012 1,409 9,028 2,075
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS (DEFICIT),
END OF PERIOD $36,240 $(1,010) $36,240 $(1,010)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE
(Note 11(a))
Basic $0.11 $(0.01) $0.14 $(0.02)
Diluted $0.11 $(0.01) $0.14 $(0.02)
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Connacher Oil and Gas Limited
Three Months Ended June 30 (Unaudited)
-------------------------------------------------------------------------
($000) 2007
-------------------------------------------------------------------------
Balance, beginning of period $4,423
-------------------------------------------------------------------------
Net earnings 22,228
Foreign currency translation adjustment (6,986)
-------------------------------------------------------------------------
Balance, end of period $19,665
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Connacher Oil and Gas Limited
Six Months Ended June 30 (Unaudited)
-------------------------------------------------------------------------
($000) 2007
-------------------------------------------------------------------------
Balance, beginning of period
-------------------------------------------------------------------------
Net earnings $27,212
Foreign currency translation adjustment (7,547)
-------------------------------------------------------------------------
Balance, end of period $19,665
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Connacher Oil and Gas Limited
Three Months Ended June 30 (Unaudited)
-------------------------------------------------------------------------
($000) 2007
-------------------------------------------------------------------------
Balance, beginning of period $(691)
Foreign currency translation adjustment (6,986)
-------------------------------------------------------------------------
Balance, end of period $(7,677)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Connacher Oil and Gas Limited
Six Months Ended June 30 (Unaudited)
-------------------------------------------------------------------------
($000) 2007
-------------------------------------------------------------------------
Balance, beginning of period $(130)
Foreign currency translation adjustment (7,547)
-------------------------------------------------------------------------
Balance, end of period $(7,677)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOW
Connacher Oil and Gas Limited
(Unaudited)
-------------------------------------------------------------------------
Three Months ended Six months ended
June 30 June 30
-------------------------------------------------------------------------
($000) 2007 2006 2007 2006
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Cash provided by (used in) the
following activities:
-------------------------------------------------------------------------
-------------------------------------------------------------------------
OPERATING
-------------------------------------------------------------------------
Net earnings (loss) $22,228 $(2,419) $27,212 $(3,085)
Items not involving cash:
Depletion, depreciation
and accretion 7,363 10,013 14,721 12,890
Stock-based compensation 333 4,800 3,279 5,194
Financing charges - non-cash
portion 324 2,300 324 2,307
Employee future benefits 122 124 252 124
Future income tax provision
(recovery) 4,102 (3,186) 5,267 (3,573)
Foreign exchange loss (gain) (14,486) 31 (16,188) 38
Dilution (gain) loss (1,896) 51 (1,896) (52)
Lease inducement amortization - (15) - (30)
Equity interest in Petrolifera
earnings (1,214) (2,200) (5,114) (2,589)
-------------------------------------------------------------------------
Cash flow from operations before
working capital changes 16,876 9,499 27,857 11,224
Changes in non-cash working
capital (Note 11(b)) (43,062) (37,742) (36,141) (33,499)
-------------------------------------------------------------------------
(26,186) (28,243) (8,284) (22,275)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
FINANCING
Issue of common shares, net of
share issue costs 238 108 518 95,030
Increase in bank debt 41,601 55,045 69,201 72,645
Repayment of bank debt (72,996) - (81,996) -
Issuance of convertible
debenture net of issue costs 96,066 - 96,066 -
Deferred financing costs - (845) - (2,792)
-------------------------------------------------------------------------
64,909 54,308 83,789 164,883
-------------------------------------------------------------------------
-------------------------------------------------------------------------
INVESTING
Acquisition and development
of oil and gas properties (91,404) (34,280) (196,698) (63,836)
Decrease in restricted cash 61,724 - 118,303 -
Acquisition of Luke Energy Ltd. - (426) - (92,654)
Acquisition of refining assets - - - (62,041)
Exercise of Petrolifera warrants
(Note 6) (5,143) - (5,143) -
Acquisition of other assets - (4,927) - (4,927)
Change in non-cash working capital
(Note 11(b)) 21,649 9,374 14,544 14,218
-------------------------------------------------------------------------
(13,174) (30,259) (68,994) (209,240)
-------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 25,549 (4,194) 6,511 (66,632)
-------------------------------------------------------------------------
Impact of foreign exchange on
foreign currency denominated
cash balances (4,660) (1,374) (5,225) (1,374)
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD - 13,073 19,603 75,511
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS,
END OF PERIOD $20,889 $7,505 $20,889 $7,505
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplementary information - Note 11
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Connacher Oil and Gas Limited
Period ended June 30, 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. ("the refinery"),
the company is in the business of exploration and development of bitumen
in the oil sands of northern Alberta, and exploring, developing,
producing, refining and marketing conventional petroleum and natural gas.
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 below and 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.
(a) Convertible debentures
The convertible debentures have been classified as term debt and equity
at their fair value at the date of issue. The fair value of the liability
component has been determined based on the company's incremental
borrowing rate for debt with similar terms. The amount of the equity
component has been determined as a residual after deducting the amount of
the liability component from the face value of the issue.
(b) Deferred share award plan for non-employee directors
Obligations for payments in cash or common shares under the company's
deferred share award plan for non-employee directors are accrued as
compensation expense over the vesting period. Fluctuations in the price
of the company's common shares change the accrued compensation expense
and are recognized when they occur.
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 six
months ended June 30, 2007 of $7,547,000 is now included in the Statement
of Comprehensive Income (Loss) (six months ended June 30, 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 and the convertible debentures, 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 and the convertible debentures, 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 and the convertible debentures
have been classified as other liabilities (as defined by the accounting
standard) and are 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.
Changes during the period in other comprehensive income and AOCI were as
follows:
-------------------------------------------------------------------------
Three months Six months
ended ended
June 30, June 30,
2007 2007
-------------------------------------------------------------------------
Increase/ Increase/
($000) (Decrease) (Decrease)
-------------------------------------------------------------------------
Other comprehensive income $(6,986) $(7,547)
Accumulated other comprehensive income (loss) $(6,986) $(7,547)
-------------------------------------------------------------------------
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:
-------------------------------------------------------------------------
June 30, December 31,
($000) 2007 2006
-------------------------------------------------------------------------
Crude oil $4,995 $3,520
Other raw materials and unfinished products(1) 1,496 1,292
Refined products(2) 27,133 17,440
Process chemicals(3) 1,371 909
Repairs and maintenance supplies and other 2,181 1,276
-------------------------------------------------------------------------
$37,176 $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) Six months ended Year ended
June 30, December 31,
2007 2006
-------------------------------------------------------------------------
Asset retirement obligations,
beginning of period $7,322 $3,108
Liabilities incurred 5,319 2,384
Liabilities acquired - 2,109
Liabilities disposed - (864)
Change in estimated future cash flows - 237
Accretion expense 433 348
-------------------------------------------------------------------------
Asset retirement obligations, end of period $13,074 $7,322
-------------------------------------------------------------------------
Liabilities incurred in 2007 have been estimated using a discount rate of
eight percent to 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. RELATED PARTY TRANSACTIONS
In May 2007, the company exercised its right to purchase 1.7 million
additional common shares in Petrolifera for total consideration of
$5.1 million. As a result, the company maintained its 26 percent equity
interest, as other Petrolifera shareholders similarly exercised their
right to purchase additional common shares in Petrolifera on identical
terms. As a consequence of this investment, the company's carrying value
of its Petrolifera investment holding increased to cause a dilution gain
of $1.9 million.
7. LONG TERM DEBT
On May 25, 2007 Connacher issued senior unsecured subordinated
convertible debentures with a face value of $100,050,000. The debentures
mature June 30, 2012 unless converted prior to that date and bear
interest at an annual rate of 4.75 percent payable semiannually on
June 30 and December 31. The debentures are convertible at any time into
common shares at the option of the holder at a conversion price of $5 per
share.
The debentures are redeemable or after June 30, 2010 by the company, in
whole or in part at a redemption price equal to 100 percent of the
principal amount of the debentures to be redeemed plus accrued and unpaid
interest provided that the market price of the company's common shares is
at least 120 percent of the conversion price of the debentures.
The conversion feature of the debentures has been accounted for as a
separate component of equity in the amount of $16,823,000. The remainder
of the net proceeds of the debentures of $79,243,000 has been recorded as
long-term debt, which will be accreted up to the face value of
$100,050,000 over the five-year term of the debentures. Accretion and
interest paid are recorded as finance charges on the consolidated
statement of operations. If the debentures are converted to common
shares, the value of the conversion feature will be reclassified to share
capital along with the principal amounts converted.
Convertible debenture initially recognized,
less issue costs of $2.8 million net of
income taxes of $1.2 million $80,463
Accretion to June 30, 2007 324
-------------------------------------------------------------------------
80,787
----------------------
----------------------
Oil sands term loan 191,772
-------------------------------------------------------------------------
$272,559
-------------------------------------------------------------------------
-------------------------------------------------------------------------
During the second quarter of 2007 the company's revolving line of credit,
backed by its conventional reserve base, was renewed for $50 million for
one year.
8. 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) 830,933 556
Shares issued to directors as compensation (b) 108,975 393
Assigned value of options exercised - 195
Tax effect of expenditures renounced
pursuant to the issuance of flow-through
common shares (c) (9,000)
Share issue costs (38)
-------------------------------------------------------------------------
Balance, Share Capital, June 30, 2007 198,833,923 $355,188
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Contributed Surplus:
Balance, December 31, 2006 $13,418
Fair value of share options granted 3,996
Assigned value of options exercised (195)
-------------------------------------------------------------------------
Balance, Contributed Surplus, June 30, 2007 $17,219
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Equity component of convertible debentures,
June 30, 2007 $16,823
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Share Capital, Contributed Surplus
and equity component:
-------------------------------------------------------------------------
December 31, 2006 $376,500
-------------------------------------------------------------------------
June 30, 2007 $389,230
-------------------------------------------------------------------------
(a) Stock options
A summary of the company's outstanding stock options, as at June 30, 2007
and 2006 and changes during those periods is presented below:
-------------------------------------------------------------------------
2007 2006
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding, beginning
of period 16,212,490 $3.31 8,592,600 $1.49
Granted 3,349,597 3.86 7,777,300 4.94
Exercised (830,933) (0.70) (742,699) (0.72)
Expired (982,000) (3.60) - -
-------------------------------------------------------------------------
Outstanding,
end of period 17,749,154 $3.52 15,627,201 $3.24
-------------------------------------------------------------------------
Exercisable,
end of period 9,693,064 $3.10 5,140,198 $2.56
-------------------------------------------------------------------------
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
Range of Exercise Prices Contractual
Life at
Number June 30,
Outstanding 2007
-------------------------------------------------------------------------
$0.20 - $0.99 2,415,302 2.4
$1.00 - $1.99 1,766,000 2.9
$2.00 - $3.99 6,438,597 4.2
$4.00 - $5.56 7,129,255 3.8
-------------------------------------------------------------------------
17,749,154
-------------------------------------------------------------------------
In the first six months of 2007 a compensatory non-cash expense of
$4.4 million (2006 - $7.1 million) was recorded, reflecting the
amortization of the fair value of stock options over the vesting period
and the fair value of shares granted to directors. Of this amount,
$3.3 million (2006 - $5.2 million) was expensed and $1.1 million (2006 -
$1.9 million) was capitalized to property and equipment.
In the second quarter of 2007 a compensatory non-cash expense of $875,000
(2006 - $6.5 million) was recorded, reflecting the amortization of the
fair value of stock options over the vesting period and the fair value of
shares granted to directors. Of this amount, $333,000 (2006 -
$4.8 million) was expensed and $542,000 (2006 - $1.7 million) 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 52% 48%
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted in the first six months of 2007 was $1.52 per option (2006 -
$1.81).
(b) Deferred share award plan for non-employee directors
Shareholders of the company approved a deferred share award incentive
plan for non-employee directors at the company's Annual and Special
meeting of Shareholders on May 10, 2007. Under the plan, a total of
326,925 deferred share units were awarded to non-employee directors. In
June 2007, 108,975 common shares were issued to directors as compensation
under the plan. The remaining 217,950 deferred share units vest one-half
on January 1, 2008 and one-half on January 1, 2009.
Under the deferred share award plan, deferred share units may be granted
to non-employee directors of the company in amounts determined by the
Board of Directors on the recommendation of the Governance Committee.
Payment under the plan is made by delivering common shares to non-
employee directors either through purchases on the TSX or by issuing
shares from treasury, subject to certain limitations. The Board of
Directors may also elect to pay cash equal to the fair market value of
the common shares to be delivered to non-employee directors upon vesting
of such deferred share units in lieu of delivering shares.
In the first six months of 2007, $393,000 was charged to expense in
respect of awards granted under the deferred share award plan.
(c) 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.
9. COMMODITY PRICE RISK MANAGEMENT
During the first quarter of 2007 the company entered into a costless
collar arrangement whereby the sales price for 5,000 mmbtu 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
commenced April 1, 2007 and continues until October 31, 2007. At June 30,
2007 the fair value of this collar was an asset of $282,000, which has
been recorded in accounts receivable on the consolidated balance sheet
and the gain has been included in PNG revenue.
10. 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.
-------------------------------------------------------------------------
Canada Canada
Oil and Adminis- USA
($000) Gas trative Refining Total
-------------------------------------------------------------------------
Three months ended June 30, 2007
Revenues, net of royalties $8,413 $- $84,628 $93,041
Equity interest in Petrolifera
earnings - 1,214 - 1,214
Dilution gain - 1,896 - 1,896
Interest and other income 111 - 114 225
Crude oil purchases and
operating costs 2,660 - 66,480 69,140
General and administrative - 1,663 - 1,663
Stock-based compensation - 333 - 333
Finance charges - 1,264 - 1,264
Foreign exchange loss (gain) (14,486) - - (14,486)
Depletion, depreciation
and accretion 5,891 - 1,472 7,363
Tax provision 3,197 - 5,674 8,871
Net earnings (loss) 11,262 (150) 11,116 22,228
Property and equipment, net 517,584 2,788 49,160 569,532
Capital expenditures 89,713 783 2,727 93,223
Total assets 668,691 36,537 116,699 821,927
-------------------------------------------------------------------------
Three months ended June 30, 2006
Revenues, net of royalties $10,171 $- $50,967 $61,138
Equity interest in
Petrolifera earnings - 2,200 - 2,200
Dilution gain (loss) - (51) - (51)
Interest and other income 15 - 86 101
Crude oil purchases and
operating costs 2,468 - 46,979 49,447
General and administrative - 1,343 - 1,343
Stock-based compensation - 4,800 - 4,800
Finance charges - 224 2,931 3,155
Foreign exchange loss (gain) 31 - - 31
Depletion, depreciation
and accretion 9,158 - 855 10,013
Tax provision (recovery) (2,797) - (185) (2,982)
Net earnings (loss) 1,326 (4,218) 473 (2,419)
Property and equipment, net 253,899 759 43,305 297,963
Capital expenditures
and acquisitions 34,023 - 257 34,280
Total assets 384,824 759 107,276 492,859
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Canada Canada
Oil and Adminis- USA
($000) Gas trative Refining Total
-------------------------------------------------------------------------
Six months ended June 30, 2007
Revenues, net of royalties $16,620 $- $142,224 $158,844
Equity interest in
Petrolifera earnings - 5,114 - 5,114
Dilution gain - 1,896 - 1,896
Interest and other income 124 - 221 345
Crude oil purchases and
operating costs 4,592 - 112,878 117,470
General and administrative - 5,248 - 5,248
Stock-based compensation - 3,279 - 3,279
Finance charges - 1,710 - 1,710
Foreign exchange loss (gain) (16,188) - - (16,188)
Depletion, depreciation
and accretion 11,992 - 2,729 14,721
Tax provision (recovery) 3,419 - 9,328 12,747
Net earnings (loss) 12,929 (3,227) 17,510 27,212
Property and equipment, net 517,584 2,788 49,160 569,532
Capital expenditures and
acquisitions 195,435 1,825 5,844 203,104
Total assets 668,691 36,537 116,699 821,927
-------------------------------------------------------------------------
Six months ended June 30, 2006
Revenues, net of royalties $13,382 $- $50,967 $64,349
Equity interest in Petrolifera
earnings and dilution gain - 2,589 - 2,589
Dilution gain - 52 - 52
Interest and other income 431 - 94 525
Crude oil purchases and
operating costs 3,300 - 46,979 50,279
General and administrative - 2,299 - 2,299
Stock-based compensation - 5,194 - 5,194
Finance charges - 308 2,931 3,239
Foreign exchange loss (gain) 38 - - 38
Depletion, depreciation
and accretion 12,035 - 855 12,890
Tax provision (recovery) (3,154) - (185) (3,339)
Net earnings (loss) 1,594 (5,160) 481 (3,085)
Property and equipment, net 253,899 759 43,305 297,963
Capital expenditures 268,832 - 66,284 335,116
Total assets 384,824 759 107,276 492,859
-------------------------------------------------------------------------
11. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the common shares used in per share
calculations.
-------------------------------------------------------------------------
For the three months ended June 30 2007 2006
-------------------------------------------------------------------------
Weighted average common shares outstanding 190,360,390 191,671,650
Dilutive effect of stock options
and deferred share units 2,591,943 7,259,755
-------------------------------------------------------------------------
Dilutive effect of convertible debentures 8,135,934 -
-------------------------------------------------------------------------
Weighed average common shares
outstanding - diluted 209,088,267 198,931,405
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the six months ended June 30 2007 2006
-------------------------------------------------------------------------
Weighted average common shares outstanding 198,240,426 173,015,395
Dilutive effect of stock options
and deferred share units 2,431,527 7,400,274
-------------------------------------------------------------------------
Dilutive effect of convertible debentures 4,090,442 -
-------------------------------------------------------------------------
Weighed average common shares
outstanding - diluted 204,762,395 180,415,669
-------------------------------------------------------------------------
For the three and six months ended June 30, 2007, $562,600 of interest and
accretion expense on the convertible debentures has been added to net income
in the numerator of the diluted earnings per share calculation.
(b) Net change in non-cash working capital
-------------------------------------------------------------------------
For the three months ended June 30 2007 2006
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Accounts receivable $(12,350) $(26,769)
Refinery inventories 1,819 (8,031)
Due from Petrolifera (38) 164
Prepaid expenses (1,012) (1,245)
Accounts payable and accrued liabilities (2,753) 7,513
Income taxes payable (7,079) -
-------------------------------------------------------------------------
Total $(21,413) $(28,368)
-------------------------------------------------------------------------
Summary of working capital changes:
-------------------------------------------------------------------------
For the three months ended June 30 2007 2006
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Operations $(43,062) $(37,742)
Investing 21,649 9,374
-------------------------------------------------------------------------
$(21,413) $(28,368)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the six months ended June 30 2007 2006
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Accounts receivable $(12,532) $(29,207)
Due from Petrolifera 73 (5)
Prepaid expenses (646) (1,256)
Refinery inventories (12,738) (8,031)
Accounts payable and accrued liabilities 11,832 19,218
Income taxes payable (7,586) -
-------------------------------------------------------------------------
Total $(21,597) $(19,281)
-------------------------------------------------------------------------
Summary of working capital changes:
-------------------------------------------------------------------------
For the six months ended June 30 2007 2006
-------------------------------------------------------------------------
($000)
Operations $(36,141) $(33,499)
Investing 14,544 14,218
-------------------------------------------------------------------------
$(21,597) $(19,281)
-------------------------------------------------------------------------
(c) Supplementary cash flow information
-------------------------------------------------------------------------
For the three months ended June 30 2007 2006
-------------------------------------------------------------------------
($000) $ $
-------------------------------------------------------------------------
Interest paid 4,152 855
Income taxes paid 6,107 -
Stock-based compensation capitalized 542 1,704
-------------------------------------------------------------------------
-------------------------------------------------------------------------
For the six months ended June 30 2007 2006
-------------------------------------------------------------------------
($000) $ $
-------------------------------------------------------------------------
Interest paid 7,599 932
Income taxes paid 9,146 -
Stock-based compensation capitalized 1,088 1,914
-------------------------------------------------------------------------
At June 30, 2007 cash of $4.5 million (December 31, 2006 -
$122.8 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 six months of 2007, $252,000 (2006 - $124,000) has been
charged to expense in relation to the refinery's defined benefit pension
plan.
FORWARD-LOOKING INFORMATION
Information in this report contains forward-looking information based on
current expectations, estimates and projections of future production, capital
expenditures and available sources of financing and estimates of reserves,
resources and future net revenues and exploration and development plans. It
should be noted forward-looking information involves a number of risks and
uncertainties and actual results may vary materially from those anticipated by
the company. There can be no assurance that the plans, intentions or
expectations upon which these forward-looking statements are based will occur.
Forward-looking statements are subject to risks, uncertainties and
assumptions, including those discussed in the company's Annual Information
Form for the year ended December 31, 2006, which include, without limitation,
changes in market conditions, law or governing policy, operating conditions
and costs, operating performance, demand for crude oil and natural gas, price
and exchange rate fluctuations, commercial negotiations, regulatory processes
and approvals and technical and economic factors. Although Connacher believes
that the expectations represented in such forward-looking statements are
reasonable, there can be no assurance that such expectations will prove to be
correct. The forward-looking statements contained herein are expressly
qualified in their entirety by this cautionary statement. The forward-looking
statements included in this MD&A are made as of the date of the MD&A and
Connacher undertakes no obligation to publicly update such forward-looking
statements to reflect new information, subsequent events or otherwise unless
so required by applicable securities laws. Throughout the MD&A, per barrel of
oil equivalent (boe) amounts have been calculated using a conversion rate of
six thousand cubic feet of natural gas to one barrel of crude oil (6:1). The
conversion is based on an energy equivalency conversion method primarily
applicable to the burner tip and does not represent a value equivalency at the
wellhead. Boes may be misleading, particularly if used in isolation.
For further information:
For further information: Richard Gusella, President and Chief Executive Officer, Connacher Oil and Gas Limited, Phone (403) 538-6201, Fax (403) 538-6225, www.connacheroil.com, inquiries@connacheroil.com
Organization Profile
Connacher Oil and Gas Limited
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