Annual Report
2007
Highlights
Financial
($ thousands, except per unit)
Production revenues
Funds from operations (1)
Per unit (1) (2)
Distributions declared
Per unit
Percentage of funds from operations (1)
Net income
Per unit (2)
Total assets
Long-term debt, including working capital deficiency
Unitholders’ equity
Capital expenditures:
Exploitation and development
Acquisitions, net
Three Months
ended
December 31,
Years
ended
December 31,
2007
2006
2007
2006
242,361
127,778
1.20
77,136
0.90
220,484
121,305
1.17
76,296
0.90
911,346
502,783
4.76
307,401
3.60
910,079
496,438
4.86
324,016
3.87
60%
63%
61%
65%
63,631
0.60
67,635
0.65
218,187
2.07
301,270
2.95
2,242,057
2,067,931
723,003
518,448
1,060,967
1,130,253
58,440
(425)
58,744
(345)
267,660
98,696
280,563
35,790
Weighted average outstanding equivalent trust units: (thousands) (2)
Basic
Diluted
106,762
109,102
103,533
106,304
105,543
108,075
102,156
105,615
Operating
(boe conversion – 6:1 basis)
Production:
Natural gas (mmcf/day)
Oil and liquids (bbls/day)
Total oil equivalent (boe/day)
Product prices: (3)
Natural gas ($/mcf)
Oil and liquids ($/bbl)
Operating expenses ($/boe)
General and administrative expenses ($/boe)
Cash costs ($/boe) (4)
Operating netback ($/boe) (5)
170
24,775
53,029
6.74
58.04
8.58
0.74
11.56
29.17
174
24,114
53,106
7.44
46.52
8.18
0.72
10.47
27.12
171
24,034
52,505
6.95
54.40
8.47
0.70
11.01
28.77
177
23,068
52,593
7.38
50.42
7.92
0.58
9.92
27.85
Highlights (cont’d)
Drilling (gross wells)
Natural gas
Oil
Average success rate
Reserves:
Proved:
Natural gas (bcf)
Oil and liquids (mbbls)
Total oil equivalent (mboe)
Proved and probable:
Natural gas (bcf)
Oil and liquids (mbbls)
Total oil equivalent (mboe)
% Proved producing
% Proved
% Probable
Net present value of future cash flow before income taxes ($ millions):
0% discount rate
5% discount rate
10% discount rate
Reserve life index (years):
Proved
Proved and probable
Finding, development and acquisition costs – proved and probable ($/boe):
Including changes in future development expenditures
Excluding changes in future development expenditures
Recycle ratio – proved and probable: (5)
Including changes in future development expenditures
Excluding changes in future development expenditures
December 31,
2007
2006
216
108
97
95%
427.1
63,724
134,911
561.0
85,955
179,454
62%
75%
25%
6,116
4,116
3,154
7.3
9.2
15.91
14.94
1.8
1.9
325
220
86
94%
428.2
63,643
135,006
542.9
83,615
174,091
62%
78%
22%
5,449
3,612
2,749
7.3
8.9
15.29
13.06
1.8
2.1
Trust Unit Trading Statistics
($ per unit, except volume)
High
Low
Close
Average Daily Volume
NOTES:
December 31,
2007
September 30,
2007
June 30,
2007
March 31,
2007
Three Months ended
31.85
24.14
28.50
31.38
27.25
29.02
33.54
29.12
30.60
31.89
25.90
30.85
275,892
177,752
216,676
230,630
(1) Management uses funds from operations to analyze operating performance, distribution coverage and leverage. Funds from operations as presented do not have any standardized
meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculations of similar measures for other entities. Funds from operations as presented is not
intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of
financial performance calculated in accordance with Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities before
changes in non-cash working capital and asset retirement expenditures. Funds from operations per unit is calculated based on the weighted average number of units outstanding
consistent with the calculation of net income per unit.
(2) Basic per unit calculations include exchangeable shares which are convertible into trust units on certain terms and conditions.
(3) Product prices include realized gains or losses on financial instruments.
(4) Cash costs equal the total of operating, general and administrative, and financing expenses.
(5) Operating netback equals production revenues including realized gains or losses on financial instruments, less royalties, transportation and operating expenses, calculated on a boe basis.
Operating netback is used in the recycle ratio calculation.
MESSAGE TO UNITHOLDERS
Bonavista Energy Trust (“Bonavista” or the “Trust”) is pleased to report to its unitholders (the “Unitholders”) its
consolidated financial and operating results for the year ended December 31, 2007. The results for the fourth
quarter of 2007 represents eighteen consecutive quarters of profitability for Bonavista since commencing operations
as an energy trust in July 2003. The continued successful execution of Bonavista’s proven strategies in the fourth
quarter of 2007 are a testament to the validity and effectiveness of an operationally and technically focused energy
trust. The fourth quarter and annual results for 2007 are also highlighted by an active and successful drilling and
acquisitions program, which has led to attractive reserve addition costs. These costs have also benefited from
somewhat lower service costs with the slowdown in industry activity in the latter half of 2007. This current
environment creates the opportunity for Bonavista to continue to differentiate itself by posting solid financial results
in an ever-changing economic landscape.
Other significant accomplishments for Bonavista in 2007 include:
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
(cid:131)
Operationally, production volumes held steady at 52,505 boe per day during 2007 versus
52,593 boe per day in 2006 and have increased 52% from 34,600 boe per day since
commencement as an energy trust on July 2, 2003. Bonavista's current production rate is
approximately 55,500 boe per day;
Added 24.5 mmboe of proved and probable reserves during 2007, which replaced annual
production by 1.3 times and also improved the Trust’s proved and probable reserve life index
to 9.2 years from 8.9 years in 2006. These reserves were added at an attractive finding,
development and acquisition cost, including changes in future development expenditures, of
$19.77 per boe on a proved basis ($19.21 per boe excluding changes in future development
expenditures) and $15.91 per boe on a proved and probable basis ($14.94 per boe excluding
changes in future development expenditures). A strong proved and probable recycle ratio of
1.8:1 (1.5:1 proved) was achieved in 2007 as a result of the low level of finding, development
and acquisition costs. Overall in 2007, Bonavista increased proved and probable reserves by
3% to 179.5 mmboe while spending 73% of funds from operations on exploitation,
development and acquisition expenditures;
Maintained an active capital program during 2007, investing $267.7 million in exploitation and
development activities. Bonavista drilled 216 wells with an overall 95% success rate, and we
spent $98.7 million on 10 synergistic acquisitions within our core regions;
Completed a strategic property acquisition in the Willesden Green area which complimented
our existing assets with a high working interest ownership and operatorship of facilities and
infrastructure. On January 14, 2008 we completed an additional acquisition of producing and
undeveloped oil and natural gas properties to further complement our operations in this area
as part of our 2008 capital program. We have assembled a new core property over the past
two years, currently producing over 5,000 boe per day;
Continued to actively participate at crown land sales, investing $33.2 million in land activity
during the year compared to $20.6 million in 2006, and further enhancing our future drilling
prospect inventory to more than three years;
Invested $18.0 million to acquire 49 sections of undeveloped land through Crown and
Freehold purchases in the light oil Bakken trend in the greater Viewfield area of southeast
Saskatchewan. We have currently drilled five wells on these lands with promising results to
date;
Generated funds from operations of $502.8 million ($4.76 per unit) in 2007 and recorded
strong profitability with net income of $218.2 million ($2.07 per unit). This resulted in an
attractive average return on equity of 20% and a strong net income to funds from operations
ratio of 43%;
Established a new $1.0 billion credit facility with a syndicate of chartered banks. This facility is
unsecured covenant-based, which significantly enhances Bonavista's financial flexibility to
take advantage of future investment opportunities in 2008 and beyond; and
Delivered top decile total returns, within the energy trust industry, to our Unitholders in 2007
and currently have a cash on cash yield of 12%. In addition, Bonavista has delivered
cumulative distributions of $1.2 billion or $15.51 per trust unit since inception of our Trust in
July 2003.
On October 25, 2007, the Government of Alberta announced its proposal for a new royalty framework in Alberta.
The proposed changes to the Alberta Crown Royalty framework are to take effect on January 1, 2009. Bonavista
will continue to analyze the information that becomes available with respect to the new crown royalty framework.
Based upon initial documentation, royalty rates will increase substantially on medium depth natural gas, high
productivity natural gas and light oil production in Alberta and as a result the economics of these opportunities have
been negatively impacted under a higher price commodity scenario. The Government of Alberta is currently
monitoring this negative impact and have indicated that, should their original decision result in unintended
consequences, the framework could be reviewed and adjusted as required to re-stimulate activity. Bonavista will
continue to assess the impact that the new royalty framework will have on our existing operations, including our
capital allocations for 2008 and beyond. Bonavista has a strong history of remaining flexible and ensuring that it
allocates capital to those projects delivering the highest rate of return and will continue to do so under this new
royalty regime.
Strengths of Bonavista Energy Trust
Since restructuring into an energy trust in July 2003, Bonavista has maintained a high level of investment activity on
its asset base, growing production by over 50% since that time. This activity stems from the operational and
technical focus of our Trust and the ability to uncover value from our assets within the Western Canadian
Sedimentary Basin. Our experienced and consistent technical teams have a solid understanding of our asset base
and possess the necessary discipline and commitment to deliver profitable results to our Unitholders for the long-
term. We actively participate in undeveloped land acquisitions through Crown land sales, property purchases or
farm-in opportunities, which have all continued to add to our already extensive low-risk drilling inventory. This has
led to low cost reserve additions, lengthening of our reserve life index, and a growing production base. Our
production base is balanced 54% in favour of natural gas and 46% towards oil and liquids and is geographically
focused within select medium depth, multi-zone regions in Alberta, Saskatchewan and British Columbia. This base
has one of the lowest operating cost structures in the oil and natural gas trust sector. In addition, these high
working interest assets are predominantly operated by Bonavista, ensuring that operating and capital cost
efficiencies are maintained and that Bonavista controls the pace of its operations. All of these attributes combined,
result in attractive operating netbacks for Bonavista.
Our team brings a successful track record of executing low to medium risk development programs, including both
asset and corporate acquisitions, along with sound financial management. Unitholders benefit from a fully
internalized, industry leading cost structure, which results in one of the lowest per unit overhead costs in the energy
trust industry. The management team, along with a strong Board of Directors, possesses extensive experience in
oil and natural gas operations, corporate governance and financial management. Directors, management and
employees also own approximately 18% of the Trust, resulting in an alignment of interests with all Unitholders.
MANAGEMENT’S DISCUSSION AND ANALYSIS
Management’s discussion and analysis (“MD&A”) of the financial condition and results of operations should be read
in conjunction with Bonavista Energy Trust’s (“Bonavista” or the “Trust”) audited consolidated financial statements
and MD&A for the year ended December 31, 2007. The following MD&A of the financial condition and results of
operations was prepared at, and is dated March 12, 2008. Our audited consolidated financial statements, Annual
Report, and other disclosure documents for 2007 will be available on or before March 30, 2008 through our filings
on SEDAR at www.sedar.com or can be obtained from Bonavista’s website at www.bonavistaenergy.com.
Basis of Presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles
(“GAAP”). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel
of oil equivalent (“boe”) using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. A boe may be misleading, particularly
if used in isolation. A boe conversion of 6 Mcf to one barrel is based on an energy equivalent conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead.
Forward-Looking Statements – Certain information set forth in this document, including management’s assessment of Bonavista’s future plans and
operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which
are beyond Bonavista’s control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations,
imprecision of reserve estimates, environmental risks, changes in environmental, tax and royalty legislation, competition from other industry participants, the
lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources.
Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may
prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Bonavista’s actual results, performance or
achievement could differ materially from those expressed in, or implied by, these forward-looking statements or if any of them do so, what benefits that
Bonavista will derive therefrom. Bonavista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of
new information, future events or otherwise, except as required by law. Investors are also cautioned that cash-on-cash yield represents a blend of return of
investor’s initial investment and a return on investors initial investment and is not comparable to traditional yield on debt instruments where investors are
entitled to full return of the principal amount of debt on maturity in addition to a return on investment through interest payments.
Non-GAAP Measurements - Within Management’s discussion and analysis, references are made to terms commonly used in the oil and natural gas
industry. Management uses "funds from operations" and the "ratio of debt to funds from operations" to analyze operating performance and leverage. Funds
from operations as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the
calculation of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for
the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated
in accordance with Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities before
changes in non-cash working capital and abandonment expenditures. Funds from operations per unit is calculated based on the weighted average number
of trust units outstanding consistent with the calculation of net income per unit. Operating netbacks equal production revenue and realized gains or losses on
financial instruments, less royalties, transportation and operating expenses calculated on a boe basis. Total boe is calculated by multiplying the daily
production by the number of days in the period. Management uses these terms to analyze operating performance and leverage.
Operations - Bonavista's exploitation and development program for the year ended December 31, 2007 led to the
drilling of 216 wells in our four core regions with an overall success rate of 95%. This program resulted in
108 natural gas wells, 97 oil wells and 11 dry holes. Bonavista continues to emphasize deeper, higher impact
drilling opportunities within the Northeast British Columbia and South Central Alberta core regions where we have
experienced excellent success and attractive finding and development costs over this period. These activities have
also lengthened our reserve life index and the predictability in our overall production base. We drilled 43 heavy oil
targets in the Lloydminster area in 2007 resulting in 100% success and relatively stable heavy oil production of
7,500 bbls per day. In addition to the exploitation and development program, Bonavista executed 10
complementary acquisitions in its core regions during 2007.
Reserves – Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards
of Disclosure (“NI 51-101”). Under NI 51-101, proved reserves are defined as reserves that can be estimated with a
high degree of certainty to be recoverable with a target of a 90% probability that the actual reserves recovered over
time will equal or exceed proved reserve estimates, while probable reserves are defined as having an equal (50%)
probability that the actual reserves recovered will equal or exceed the proved and probable reserve estimates. In
accordance with NI 51-101, proved undeveloped reserves have been recognized in cases where plans are in place
to bring the reserves on production within a short, well defined time frame. Proved undeveloped reserves often
involve infill drilling into existing pools. Of the Trust’s net present value reserves, 81% were evaluated by
independent third party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") and Ryder Scott Company Canada in
their reports dated February 26th, 2008 and March 4th, 2008 respectively, depending on the location of the property.
The balance of approximately 19% of proved and probable reserves was evaluated internally. The reserve
estimates contained in the following tables represent Bonavista's interest reserves before the deduction of royalties:
Proved:
Proved producing
Proved non-producing
Proved undeveloped
Total proved (1)
Probable
Total proved and probable (1)
Natural Gas
(bcf)
Oil and
Liquids
(mbbls)
Total
Reserves
(mboe)
0%
Net Present Value @
5%
(millions)
10%
373.0
27.3
26.8
427.1
133.9
561.0
49,729
5,745
8,249
63,724
22,231
111,887
10,302
12,722
134,911
44,543
$ 3,704
262
492
$ 2,713
201
297
$ 2,187
161
203
4,457
1,659
3,211
906
2,551
603
85,955
179,454
$ 6,116
$ 4,116
$ 3,154
Proved:
December 31, 2006
Exploitation and development
Revisions (2)
Acquisitions, net
Production
December 31, 2007 (1)
Proved and probable:
December 31, 2006
Exploitation and development
Revisions (2)
Acquisitions, net
Production
December 31, 2007 (1)
(1) Numbers may not add due to rounding.
(2) Revisions include economic factors.
Natural Gas
(bcf)
428.2
35.2
2.9
23.2
(62.4)
427.1
542.9
45.7
7.1
27.7
(62.4)
561.0
Oil and
Liquids
(mbbls)
63,643
6,279
(509)
3,085
(8,773)
63,724
83,615
8,637
(1,212)
3,688
(8,773)
85,955
Total
Reserves
(mboe)
135,006
12,139
(28)
6,959
(19,165)
134,911
174,091
16,260
(32)
8,300
(19,165)
179,454
Bonavista’s 2007 year-end proved reserves totalled 134.9 mmboe, essentially unchanged compared to the 135.0
mmboe at the year-end of 2006. Bonavista’s proved and probable reserves increased by 3% to 179.5 mmboe
when compared to the 174.1 mmboe at year-end 2006. Bonavista’s proved and probable reserve life index (“RLI”)
also increased during the year to 9.2 years, with the proved RLI at 7.3 years. Finding, development and acquisition
costs in 2007, including changes in future capital expenditures, amounted to $19.77 per boe ($19.21 per boe before
changes in future capital expenditures) on a proved basis and $15.91 per boe ($14.94 per boe before changes in
future capital expenditures) on a proved and probable basis. The aggregate of the exploration and development
costs incurred in the most recent financial year and the change during the year in estimated future development
costs generally will not reflect total finding and development costs relating to reserve additions for that year.
Bonavista generated attractive recycle ratios of 1.8:1 for proved and probable reserves and 1.5:1 for proved
reserves, including revisions and changes in future development expenditures; excluding changes in future
development expenditures, the proved and probable recycle ratio increased to 1.9:1 and the proved recycle ratio
remains unchanged at 1.5:1. Additional reserves disclosure tables, as required under NI 51-101, are contained in
Bonavista’s Annual Information Form that will be filed on SEDAR.
On October 25, 2007, the Government of Alberta announced its proposal for a New Royalty Framework ("NRF") in
Alberta. The NRF is anticipated to take effect January 1, 2009, this will result in the Trust's royalty rates for the low
value sensitivity case to increase by less than one percent. The net present value of the Trust's total reserves will
decrease by less than two percent using GLJ's forecasted prices as at January 1, 2008 and a 10% discount rate.
Financial and operating highlights – The following is a summary of key financial and operating results for the
respective periods noted:
($ thousands, except per boe/Trust Unit Amounts and where noted)
Product prices:
Natural gas ($/mcf)
Oil and liquids ($/bbl)
Production:
Natural gas (mmcf/d)
Oil and liquids (bbls/d)
Total production (boe/d)
Production revenues
per boe
Royalties
per boe
% of Production revenues
Operating expenses
per boe
Transportation expenses
per boe
General and administrative expenses
per boe
Financing expenses
per boe
Funds from operations
per boe
per unit – basic
Unit-based compensation
per boe
Depreciation, depletion and accretion
per boe
Income taxes (reduction)
per boe
Net income
per boe
per unit – basic
Distributions declared
per unit
Three Months
ended
December 31,
Years
ended
December 31,
2007
2006
2007
2006
6.74
58.04
7.44
46.52
6.95
54.40
7.38
50.42
170
24,775
53,029
242,361
49.68
42,809
8.77
17.7%
41,867
8.58
10,364
2.12
3,620
0.74
10,915
2.24
127,778
26.19
1.20
2,809
0.58
60,467
12.39
(30,831)
(6.32)
63,631
13.04
0.60
77,136
0.90
174
24,114
53,106
220,484
45.13
38,985
7.98
17.7%
39,945
8.18
10,874
2.23
3,532
0.72
7,684
1.57
121,305
24.83
1.17
714
0.15
56,179
11.50
(3,424)
(0.70)
67,635
13.84
0.65
76,296
0.90
171
24,034
52,505
911,346
47.55
177
23,068
52,593
910,079
47.41
155,586
8.12
17.1%
174,903
9.11
19.2%
162,371
8.47
41,397
2.16
13,335
0.70
35,209
1.84
502,783
26.24
4.76
7,351
0.38
231,945
12.10
(535)
(0.03)
218,187
11.39
2.07
307,401
3.60
152,087
7.92
40,065
2.09
11,229
0.58
26,960
1.40
496,438
25.86
4.86
4,890
0.25
214,698
11.18
(25,215)
(1.31)
301,270
15.69
2.95
324,016
3.87
Production - Overall for 2007 production was 52,505 boe per day, largely unchanged when compared to
52,593 boe per day for the same period a year ago. More specifically, average natural gas production decreased
3% to 171 mmcf per day in 2007 from 177 mmcf per day for the same period a year ago, while total oil and liquids
production increased 4% to 24,034 bbls per day (comprised of 16,486 bbls per day of light and medium oil and
7,548 bbls per day of heavy oil) from 23,068 bbls per day (comprised of 16,007 bbls per day of light and medium oil
and 7,061 bbls per day of heavy oil) for the same period in 2006. This trend was the result of a decision made
earlier in 2007 to emphasize crude oil projects over natural gas projects due to the favorable oil economics. For the
fourth quarter of 2007, production was also essentially unchanged at 53,029 boe per day when compared to 53,106
boe per day for the same period in 2006. Natural gas production decreased 2% to 170 mmcf per day in the fourth
quarter of 2007 from 174 mmcf per day for the same period a year ago, while total oil and liquids production
increased 3% to 24,775 bbls per day in the fourth quarter of 2007 (comprised of 16,825 bbls per day of light and
medium oil and 7,950 bbls per day of heavy oil) from 24,114 bbls per day (comprised of 16,559 bbls per day of light
and medium oil and 7,555 bbls per day of heavy oil) for the same period a year ago. Our current production is
approximately 55,500 boe per day consisting of 54% natural gas, 33% light and medium oil and 13% heavy oil.
Bonavista's diversified commodity investment approach minimizes our dependence on any one product.
Revenues - Revenues, excluding gains and losses on financial instruments, for the year ended December 31, 2007
increased slightly to $911.3 million when compared to $910.1 million for the same period a year ago. For the year
ended December 31, 2007, our natural gas price including realized gains on financial instruments averaged $6.95
per mcf, a decrease of 6% from $7.38 per mcf for the same period in 2006. The average oil and liquids price
increased 8% to $54.40 per bbl (comprised of $58.61 per bbl for light and medium oil and $45.20 per bbl for heavy
oil) for the year ended December 31, 2007 from $50.42 per bbl (comprised of $53.94 per bbl for light and medium oil
and $42.45 per bbl for heavy oil) for the same period in 2006. Revenues, excluding gains and losses on financial
instruments, for the fourth quarter of 2007 increased by 10% to $242.4 million when compared to $220.5 million in
the fourth quarter of 2006 due to higher average commodity prices. In the fourth quarter of 2007, natural gas prices
averaged $6.74 per mcf, down 9% from $7.44 per mcf for the same period in 2006. The average oil and liquids
price increased 25% to $58.04 per bbl (comprised of $62.32 per bbl for light and medium oil and $48.99 per bbl for
heavy oil) in the fourth quarter of 2007 from $46.52 per bbl (comprised of $49.37 per bbl for light and medium oil and
$40.28 per bbl for heavy oil) for the same period in 2006.
Commodity price risk management - As part of our financial management strategy, Bonavista has adopted a
disciplined commodity price risk management program. The purpose of this program is to stabilize funds from
operations against unpredictable commodity prices and protect acquisition economics. Bonavista’s Board of
Directors has approved a commodity price risk management limit of 60% of forecast production, net of royalties,
primarily using costless collars. Our strategy of using costless collars limits Bonavista’s exposure to downturns in
commodity prices, while allowing for participation in commodity price increases.
Prior to January 1, 2007, Bonavista accounted for all of our financial contracts as hedges and included realized
gains or losses in revenues. On January 1, 2007, with the adoption of new accounting standards for financial
instruments and hedging, Bonavista discontinued hedge accounting treatment for our financial commodity
derivative contracts. Accordingly, realized and unrealized gains on these financial instruments are recognized in
the current period. See note 3 of the audited consolidated financial statements for the year ended
December 31, 2007.
For the year ended December 31, 2007, our risk management program on financial instruments resulted in a net
loss of $45.7 million, consisting of a realized loss of $665,000 and an unrealized loss of $45.1 million. The realized
loss of $665,000 consisted of a $5.2 million gain on natural gas commodity derivative contracts and a $5.9 million
loss on crude oil commodity derivative contracts. For the three months ended December 31, 2007, our risk
management program on financial instruments resulted in a net loss of $36.5 million, consisting of a realized loss of
$5.0 million and an unrealized loss of $31.5 million. The realized loss of $5.0 million consisted of a $1.7 million gain
on natural gas commodity derivative contracts and a $6.7 million loss on crude oil commodity derivative contracts.
The following is a summary of commodity price risk management contracts as at December 31, 2007.
i) Financial instruments:
The Trust has hedged by way of costless collars to sell natural gas (gjs/d) and crude oil (bbls/d) as follows:
Volume
Average Price
Term
5,000 gjs/d
5,000 gjs/d
7,000 bbls/d
1,000 bbls/d
2,000 bbls/d
- CDN$ 10.55 – AECO
- CDN$ 9.00 – AECO
- US$ 78.58 – WTI
CDN$ 7.50
CDN$ 7.00
US$ 65.43
CDN$ 49.00 - CDN$ 57.00 – Bow River
US$ 65.00
- US$ 80.50 – WTI
January 1, 2008 – March 31, 2008
April 1, 2008 – October 31, 2008
January 1, 2008 – December 31, 2008
January 1, 2008 – December 31, 2008
January 1, 2009 – March 31, 2009
As at December 31, 2007, the market deficit of these derivative financial instruments was approximately
$45.1 million.
ii) Physical purchase contracts:
The Trust has entered into direct sale costless collars to sell natural gas as follows:
Volume
Average Price (CDN$ - AECO)
Term
20,000 gjs/d
$ 7.75 - $ 10.53
January 1, 2008 – March 31, 2008
Subsequent to December 31, 2007, the Trust has entered into the following commodity contracts:
i) Financial instruments:
The Trust has hedged by way of costless collars to sell natural gas (gjs/d) and crude oil (bbls/d) as follows:
Volume
Average Price
Term
20,000 gjs/d
2,000 bbls/d
1,000 bbls/d
- CDN$ 8.46 – AECO
CDN$ 7.38
CDN$ 61.00 - CDN$ 71.75 – Bow River
US$ 85.00
- US$ 105.60 – WTI
April 1, 2008 – October 31, 2008
April 1, 2008 – December 31, 2008
January 1, 2009 – December 31, 2009
ii) Physical purchase contracts:
The Trust has entered into direct sale costless collars to sell natural gas as follows:
Volume
Average Price (CDN$ - AECO)
Term
45,000 gjs/d
25,000 gjs/d
$ 7.19 - $ 8.36
$ 7.65 - $ 9.65
April 1, 2008 – October 31, 2008
November 1, 2008 – March 31, 2009
Royalties - For the year ended December 31, 2007, royalties decreased 11% to $155.6 million from $174.9 million
for the same period a year ago, primarily due to lower natural gas prices and favourable crown royalty adjustments
relating to prior periods. In addition, royalties as a percentage of revenue including realized gains and losses on
financial instruments decreased to 17.1% from 19.4% in 2006 primarily due to similar reasons. For the year ended
December 31, 2007, royalties by product, as a percentage of revenue including realized gains and losses on
financial instruments were 17.6% for natural gas, 16.8% for light and medium oil and 16.0% for heavy oil. For the
year ended December 31, 2006, royalties by product, as a percentage of revenue including realized gains and
losses on financial instruments were 21.1% for natural gas, 18.6% for light and medium oil and 14.1% for heavy oil.
For the three months ended December 31, 2007, royalties increased 10% to $42.8 million from $39.0 million for the
same period a year ago, largely attributed to increased heavy oil royalties resulting from the payout of two oil sand
royalty projects. In addition, royalties as a percentage of revenue including realized gains and losses on financial
instruments for the fourth quarter of 2007 also increased from 17.5% in 2006 to 18.0% in 2007 for similar reasons
discussed above. For the three months ended December 31, 2007, royalties by product as a percentage of
revenues including realized gains and losses on financial instruments were 18.1% for natural gas, 17.8% for light
and medium oil and 18.4% for heavy oil. For the three months ended December 31, 2006, royalties by product, as a
percentage of revenue including realized gains and losses on financial instruments were 18.9% for natural gas,
17.3% for light and medium oil and 12.4% for heavy oil.
Operating expenses - Operating expenses for the year ended December 31, 2007 increased 7% to $162.4 million
compared to $152.1 million for the same period a year ago. Operating expenses for the fourth quarter of 2007
increased 5% to $41.9 million compared to $39.9 million for the same period a year ago. Over the past several
months, operating costs have shown signs of stabilizing as we have experienced a slow-down in industry activity
due to lower natural gas prices and the proposed changes to the Alberta Royalty framework. Average per unit
operating costs for the year ended December 31, 2007 increased to $8.47 per boe which is up 7% from $7.92 per
boe in the comparable period of 2006. For 2007, per unit operating expenses by product were $1.17 per mcf for
natural gas, $9.16 per bbl for light and medium oil and $12.36 per bbl for heavy oil compared to $1.12 per mcf for
natural gas, $8.73 per bbl for light and medium oil and $10.95 per bbl for heavy oil for 2006. For the three months
ended December 31, 2007, operating costs increased 5% to $8.58 per boe from $8.18 per boe in the comparable
period of 2006. Operating costs by product for the fourth quarter of 2007 were $1.16 per mcf for natural gas, $9.31
per bbl for light and medium oil and $12.72 per bbl for heavy oil compared to $1.13 per mcf for natural gas, $8.85
per bbl for light and medium oil and $11.70 per bbl for heavy oil. Notwithstanding the year over year increases,
Bonavista continues to place significant emphasis on the control of operating costs and is continuing to pursue cost
reduction initiatives.
Transportation expenses - Transportation expenses for the year ended December 31, 2007 increased to
$41.4 million ($2.16 per boe) compared to $40.1 million ($2.09 per boe) in 2006. For the three months ended
December 31, 2007, transportation expenses decreased 5% to $10.4 million ($2.12 per boe) when compared to
$10.9 million ($2.23 per boe) for the same period last year. The increase in transportation expenses year to date
was primarily due to the increase in trucking costs per barrel for heavy oil along with an increase in heavy oil
volumes. These increases have been offset by a decrease in natural gas transportation due to the expiry of certain
firm export service obligations. Transportation expenses for the fourth quarter of 2007 decreased as compared to
the same period in 2006 primarily as a result of lower realized gas transportation costs. Transportation expenses by
product for the year ended December 31, 2007 were $0.44 per mcf for natural gas, $0.92 per bbl for light and
medium oil and $3.18 per bbl for heavy oil compared to $0.43 per mcf for natural gas, $0.86 per bbl for light and
medium oil and $2.87 per bbl for heavy oil for the same period in 2006. For the fourth quarter of 2007,
transportation expenses by product were $0.43 per mcf for natural gas, $0.86 per bbl for light and medium oil and
$3.19 per bbl for heavy oil compared to $0.46 per mcf for natural gas, $0.85 per bbl for light and medium oil and
$3.12 per bbl for heavy oil for the same period a year ago.
General and administrative expenses - General and administrative expenses, after overhead recoveries, for the
year ended December 31, 2007 increased 19% to $13.3 million from $11.2 million in the same period in 2006 and
increased 3% to $3.6 million for the three months ended December 31, 2007 from $3.5 million in the same period in
2006. On a per boe basis, general and administrative expenses increased 21% for the year ended
December 31, 2007 to $0.70 per boe from $0.58 per boe in the same period in 2006 and increased 3% for the three
months ended December 31, 2007 to $0.74 per boe from $0.72 per boe in the same period in 2006. This increase
is largely due to the higher staffing levels required to manage our operations and increasing general cost pressures
currently experienced throughout the industry. In addition, through a services agreement with NuVista Energy Ltd.,
Bonavista provides certain administrative activities. The fee charged under this agreement was $1.4 million for the
year ended December 31, 2007 as compared to $2.3 million in the same period in 2006 and $400,000 for the three
months ended December 31, 2007 as compared to $698,000 in 2006. In connection with its Trust Unit Incentive
Rights Plan, Bonavista also recorded a unit-based compensation charge of $7.4 million and $2.8 million for the year
and three months ended December 31, 2007 respectively, compared to $4.9 million and $714,000 for the same
periods in 2006.
Financing expenses - Financing expenses, which include interest expense on long-term debt and convertible
debentures, increased to $35.2 million for the year ended December 31, 2007, from $27.0 million for the same
period in 2006 and on a boe basis increased to $1.84 per boe for the year ended December 31, 2007 from
$1.40 per boe in the same period in 2006. For the three months ended December 31, 2007, financing expenses
increased to $10.9 million from $7.7 million for the same period in 2006 and on a boe basis increased to $2.24 per
boe for the three months ended December 31, 2007 from $1.57 per boe for the same period in 2006. These
increases are due to higher interest rates and increased debt levels used to fund Bonavista's capital program.
Amortization and accretion expenses related to the Trust’s convertible debentures for the year ended
December 31, 2007 decreased to $777,000 from $860,000 for the same period in 2006. For the three months
ended December 31, 2007 amortization and accretion expenses decreased to $192,000 from $197,000 for the
same period in 2006. This decrease is largely attributable to the conversion of debentures into Trust Units since
December 31, 2006. The amortization component reflects the charge to net income of the debenture issue costs
over the term of the debenture. The fair value of the conversion option of the debentures is classified as equity.
Over the term of the debentures, the carrying value will accrete to the principal balance at maturity, with the charge
to accretion expense on convertible debentures. For the year ended December 31, 2007 Bonavista paid cash
interest of $35.4 million compared to $26.8 million for the same period in 2006. During the fourth quarter of 2007,
Bonavista paid cash interest of $11.3 million compared to $7.9 million in 2006.
Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 8%
to $231.9 million for the year ended December 31, 2007 from $214.7 million for the same period in 2006. For the
three months ended December 31, 2007 depreciation, depletion and accretion expenses also increased by 8% to
$60.5 million from $56.2 million in the same period of 2006. Both increases were due to higher costs of finding and
developing reserves and a larger asset base in 2007. For the year ended December 31, 2007 the average cost
increased to $12.10 per boe from $11.18 per boe for the same period in 2006 and for the three months ended
December 31, 2007 the average cost increased to $12.39 per boe from $11.50 per boe for the same period a year
ago. The increase in depreciation, depletion and accretion expenses are due to increased costs associated with
adding reserves. Over the past few years our industry has seen tremendous cost escalation due to the heavy
demand for oilfield services, in particular drilling and service rig activities. These costs are showing signs of
alleviating, the result of an industry-wide slowdown due to the lower natural gas prices realized throughout the past
year and the uncertainty surrounding the new Alberta Royalty framework.
Income taxes - For the year ended December 31, 2007, the provision for income taxes was a recovery of $535,000
compared to a recovery of $25.2 million for the same period of 2006. For the three months ended
December 31, 2007, the provision for income tax was a recovery of $30.8 million compared to a recovery of
$3.4 million for the same period in 2006. The income tax provision for the year ended December 31, 2007 includes
a $36.4 million future income tax charge resulting from recent changes to income tax legislation substantively
enacted in the second and fourth quarters of 2007 that modify the taxation of certain flow through entities, including
mutual fund trusts and their unitholders. The provision arose as the book basis of the assets and liabilities held in
the Trust and a subsidiary trust exceeded their tax basis. Previously, future income taxes were recorded only on the
temporary differences in the corporate subsidiaries of the Trust. In addition, the provision for the year ended
December 31, 2007 includes a recovery of $9.6 million related to tax rate reductions enacted during the second and
fourth quarters of 2007. Bonavista made no cash payments relating to installments for either of the three months
and year ended December 31, 2007, compared to nil and $785,000, respectively, for the same periods a year ago.
Funds from operations, net income and comprehensive income - For the year ended December 31, 2007,
Bonavista experienced a 1% increase in funds from operations to $502.8 million ($4.76 per unit, basic) from
$496.4 million ($4.86 per unit, basic) for the same period in 2006. For the three months ended December 31, 2007,
Bonavista experienced a 5% increase in funds from operations to $127.8 million ($1.20 per unit, basic) from $121.3
million ($1.17 per unit, basic) for the same period in 2006. Funds from operations increased for the year and three
months ended December 31, 2007 primarily due to higher realized oil and liquids product prices and higher oil and
liquids volumes. Net income for the year ended December 31, 2007, decreased 28% to $218.2 million ($2.07 per
unit, basic) from $301.3 million ($2.95 per unit, basic) for the same period of 2006. The decrease is largely due to
higher depletion and depreciation expenses and the recognition of unrealized losses on financial instruments and
the higher provisions for income taxes. For the three months ended December 31, 2007, net income decreased 6%
to $63.6 million ($0.60 per unit, basic) from $67.6 million ($0.65 per unit, basic) for the same period in 2006. The
decrease in net income, prior to the tax provision to reflect the enactment of the taxation changes, for the year
ended December 31, 2007, was largely due to a recovery relating to the reduction in future federal and provincial
income tax rates enacted during the fourth quarter of 2006 and the recognition of unrealized losses on financial
instruments. Other comprehensive income for the year ended December 31, 2007 included a charge of $6.0 million,
(2006 – nil) relating to the amortization of the amount recognized in accumulated other comprehensive income on
January 1, 2007 for the fair value of financial instruments on adoption of the new accounting standards for financial
instruments. This resulted in total comprehensive income for the year ended December 31, 2007 of $212.2 million
(2006 – $301.3 million). Other comprehensive income for the three months ended December 31, 2007 included a
charge of $2.5 million, (2006 – nil) relating to the amortization of the amount recognized in accumulated other
comprehensive income on January 1, 2007 for the fair value of financial instruments on adoption of the new
accounting standards for financial instruments. This resulted in total comprehensive income for the three months
ended December 31, 2007 of $61.1 million (2006 – $67.6 million).
The following table is a reconciliation of a non-GAAP measure, funds from operations, to its nearest measure
prescribed by GAAP:
Calculation of Funds From Operations:
(thousands)
Cash flow from operating activities
Increase in non-cash working capital
Asset retirement expenditures
Three Months ended
December 31,
2007
2006
Years ended
December 31,
2007
2006
$
95,459
27,535
4,784
$
94,456
23,987
2,862
$ 473,021
21,424
8,338
$ 475,050
15,694
5,694
Funds from operations
$ 127,778
$ 121,305
$ 502,783
$ 496,438
Capital expenditures - Capital expenditures for the year ended December 31, 2007 were $366.4 million, which
consisted of $267.7 million of exploitation and development spending and $98.7 million of net property acquisitions.
The total capital expenditures of $366.4 million was slightly higher than budget due to an increase in our crown land
expenditures and planned $8.5 million disposition of northeast Alberta natural gas assets to a junior oil and natural
gas company that was not consummated. For the same period in 2006, capital expenditures were $316.4 million
consisting of $280.6 million of exploitation and development spending and $35.8 million of net property acquisitions.
Capital expenditures for the three month period ended December 31, 2007 were $58.0 million, consisting of $58.4
million on exploitation and development spending and $425,000 of dispositions. For the same period in 2006
capital expenditures were $58.4 million, consisting of $58.7 million of exploitation and development spending and
$345,000 of dispositions. With the industry currently experiencing cost reductions in many of its services due to
lower industry activity levels, Bonavista too is benefiting with its active drilling program which is generating
production addition costs at attractive levels. Entering 2008, we continue to generate favourable economic returns
from our capital expenditure program as a direct result of the recent decrease in service costs coupled with
strengthening commodity prices.
The following table outlines capital expenditures by category for the years ended December 31, 2007 and 2006:
(thousands)
Land acquisitions
Geological and geophysical
Drilling and completion
Production equipment and facilities
Other
Exploitation and development expenditures
Acquisitions
Dispositions
Years ended
December 31,
2007
2006
$
33,211
9,811
139,578
84,444
616
267,660
100,806
(2,110)
$
20,608
8,824
172,538
78,012
581
280,563
36,155
(365)
Net capital expenditures
$
366,356
$
316,353
Liquidity and capital resources - As at December 31, 2007, long-term debt including working capital deficiency,
was $723.0 million with an attractive debt to 2007 funds from operations ratio of 1.4:1 (1.5:1 including convertible
debentures). With our bank credit facility recently increased to $1.0 billion in August 2007, Bonavista has
$277.0 million of unused bank borrowing capability, leaving significant flexibility to finance future expansions in our
capital programs or acquisition opportunities as they arise.
In 2008, Bonavista plans to invest approximately $400 to $420 million to expand its core regions, which will be
financed through a combination of funds from operations and bank debt. The Trust is committed to the fundamental
principle of maintaining financial flexibility and the prudent use of debt. As such, the 2008 capital expenditure
program is based on using a conservative amount of debt in our financing structure.
Under the terms of the credit facility, the Trust has provided the covenant that its consolidated senior debt borrowing
will not exceed three times net income before interest, taxes and depreciation, depletion and accretion; consolidated
total debt will not exceed three and one half times consolidated net income before interest, taxes and depreciation,
depletion and accretion; and consolidated senior debt borrowing will not exceed one-half of consolidated total debt
plus consolidated unitholders’ equity of the Trust.
Subsequent event - On January 14, 2008, we completed the acquisition of producing and undeveloped oil and
natural gas properties in the Willesden Green area of our South Central Alberta core regions and the Fireweed area
located in our Northeast British Columbia core region for proceeds of $167 million. The acquisition added
approximately 3,800 boe per day; comprised of 14 mmcf per day of natural gas, 700 bbls per day of associated
natural gas liquids and 800 bbls per day of light crude oil.
Unitholders’ equity - As at December 31, 2007, Bonavista had 106.8 million equivalent trust units outstanding.
This includes 12.2 million exchangeable shares, which are exchangeable into 21.1 million trust units. The exchange
ratio in effect at December 31, 2007 for exchangeable shares was 1.72244:1. As at March 12, 2008, Bonavista had
107.7 million equivalent trust units outstanding. This includes 12.2 million exchangeable shares, which are
exchangeable into 21.5 million trust units. The exchange ratio in effect at March 12, 2008 for exchangeable shares
was 1.76049:1. In addition, Bonavista has 3.3 million trust unit incentive rights outstanding at March 12, 2008, with
an average exercise price of $27.26 per trust unit.
As at December 31, 2007, Unitholders’ equity included $1.1 million for the ascribed value of the conversion feature
of the convertible debentures. This amount was determined at the time the debentures were issued and was
subsequently reduced by the amounts attributed to debentures that have been converted into trust units. Of the
100,000, 7.5% convertible debentures issued on January 29, 2004, there have been 92,206 of these debentures
converted into trust units, leaving 7,794 debentures with a principal amount of $7.8 million outstanding as at
December 31, 2007. On December 31, 2004, the Trust issued 135,000, 6.75% convertible debentures in
conjunction with a property acquisition in British Columbia. The original issue of these debentures had a principal
amount of $135.0 million, and from the date of issuance to December 31, 2007 there have been 91,698 of these
debentures converted into trust units, leaving 43,302 debentures outstanding with a principal amount of
$43.3 million.
Contractual obligations - The following is a summary of the Trust’s contractual obligations and commitments as at
December 31, 2007:
(thousands)
Long-term debt repayments (1)
Convertible debentures
Transportation expenses
Office premises
Total
2008
2009
2010
2011
2012 and
thereafter
Payments Due by Period
$ 712,654
51,096
24,706
4,762
$
-
-
12,657
1,527
$
-
7,794
8,127
1,527
$ 712,654
43,302
1,324
1,412
$
-
-
953
296
$
-
-
1,645
-
Total contractual obligations
$ 793,218
$ 14,184
$ 17,448
$ 758,692
$ 1,249
$ 1,645
(1)
Based on the existing terms of the revolving credit facility, the first payment may be required in 2010. However, it is expected that the revolving credit facility
will be extended and no repayments will be required in the near term.
Distributions – Bonavista's distribution policy is constantly monitored and is dependent upon its forecasted
operations, funds from operations, debt levels and capital expenditures. One of the paramount objectives of the
Trust is to be a sustainable entity, which is defined as maintaining both production and reserves over an extended
period of time. This is accomplished by retaining sufficient funds from operations to replace the reserves that have
been produced. With these considerations, for the year ended December 31, 2007 the Trust declared distributions
of $307.4 million compared to $324.0 million in the same period in 2006. For the three months ended
December 31, 2007 the Trust declared distributions of $77.1 million compared to $76.3 million in the same period in
2006.
The following table illustrates the relationship between cash flow provided from operating activities and distributions
declared, as well as net income and distributions declared. Net income includes significant non-cash charges that
do not impact cash flow. For the year and three months ended December 31, 2007, the non-cash charges
amounted to $284.6 million and $64.1 million respectively compared to $195.2 million and $53.7 million for the
same periods in 2006. Net income also includes fluctuations in future income taxes due to changes in tax rates and
tax rules. In addition, other non-cash charges, such as depreciation, depletion and accretion and unrealized gains
and losses on financial instruments, do not represent the actual cost of maintaining our productive capacity given
the natural declines associated with oil and gas assets. In these instances, where distributions exceed net income,
a portion of the cash distribution paid to Unitholders may be considered an economic return of Unitholders' capital.
Distribution Analysis
(thousands)
Cash flow provided from operating activities
Net income
Distributions declared
Excess of cash flow provided from operating
activities over distributions declared
Excess (shortfall) of net income over
distributions declared
$
Three Months ended
December 31,
2007
95,459
63,631
77,136
18,323
$
2006
94,456
67,635
76,296
18,160
Years ended
December 31,
2007
2006
$
473,021
218,187
307,401
165,620
$ 475,050
301,270
324,016
151,034
(22,746)
(13,505)
(8,661)
(89,214)
Bonavista announces its distribution policy on a quarterly basis. Distributions are determined by the Board of
Directors and are dependent upon the commodity price environment, production levels, and the amount of capital
expenditures to be financed from funds from operations. Bonavista’s current monthly distribution rate is $0.30 per
trust unit. This monthly distribution is comprised of the base distribution of $0.28 per trust unit plus a supplementary
distribution of $0.02 per unit, due to the average realized commodity prices in excess of budget prices. The base
distribution rate assumes realized commodity prices of CDN $8.00 per gj at AECO for natural gas and CDN $60.00
per barrel at Edmonton for light crude (this equates to approximately US $9.30 per mmbtu for NYMEX natural gas
and US $60.00 per barrel for WTI crude oil). The combined base and supplementary distribution incorporates the
withholding of sufficient funds from operations to fund capital expenditures required to maintain or modestly grow
the current production base and provide sustainable distributions in the long-term. Our long-term objective is to
distribute between 50% and 60% of our funds from operations. Our current distribution rate of $0.30 per trust unit
per month places us in this range for 2008, based on the current market of commodity price futures.
Annual financial information - The following table highlights selected annual financial information for each of the
three years ended December 31, 2007, 2006 and 2005:
Years ended December 31,
2007
2006
2005
(thousands, except per unit amounts)
Consolidated Statement of Operations Information:
Production revenues, net of royalties
Funds from operations
Per unit – basic
Per unit – diluted
Net income
Per unit – basic
Per unit – diluted
Consolidated Balance Sheet Information:
Total capital expenditures
Total assets
Working capital (deficiency)
Long-term debt
Unitholders’ equity
Distributed declared
$ 755,760
502,783
4.76
4.69
218,187
2.07
2.06
$ 366,356
2,242,057
(10,349)
712,654
1,060,967
307,401
$ 735,176
496,438
4.86
4.74
301,270
2.95
2.90
$ 316,353
2,067,931
(6,125)
512,323
1,130,253
324,016
$ 730,733
522,649
5.41
5.17
302,942
3.14
3.05
$ 295,052
1,934,892
(27,907)
343,802
1,103,510
270,827
Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly
periods ending on March 31, 2006 to December 31, 2007:
December 31 September 30
June 30
March 31
December 31 September 30
June 30
March 31
2007
2006
($ thousands, except per unit amounts)
Production revenues
Net income
Net income per unit:
242,361
63,631
219,885
58,990
223,878
33,936
225,222
61,630
220,484
67,635
227,270
70,800
229,492
87,425
232,833
75,410
Basic
Diluted
0.60
0.59
0.56
0.55
0.32
0.32
0.59
0.59
0.65
0.65
0.69
0.68
0.86
0.84
0.75
0.74
Production revenue, excluding gains and losses on financial instruments were 4% higher in the fourth quarter of
2007 versus the first quarter of 2006, primarily due to both slightly higher production volumes and average product
prices. Net income decreased 16% in the fourth quarter of 2007 as compared to the first quarter of 2006. The
decrease in net income in the fourth quarter of 2007 is attributed to a $31.5 million charge to net income to reflect
the unrealized losses on financial instruments. The decrease in net income in the second quarter of 2007 is
attributable to the non-cash future income tax charge to net income of $41.0 million to reflect recent changes to
income tax legislation, substantially enacted in the second quarter of 2007.
Disclosure and Internal Controls - Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by Bonavista is accumulated and communicated to management, as
appropriate, to allow timely decisions regarding required disclosures. The Chief Executive Officer and Chief
Financial Officer have concluded, as of the end of the period covered by the interim filings, that Bonavista’s
disclosure controls and procedures are effectively designed to provide reasonable assurance that material
information related to the issuer is made known to them by others within the Trust. It should be noted that while the
Trust’s Chief Executive Officer and Chief Financial Officer believe that the disclosure controls and procedures
provide a reasonable level of assurance that they are effective, they do not expect that the 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 objective of the
control system is met.
Internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of
the Trust's financial reporting and compliance with generally accepted accounting principles ("GAAP"). The CEO
and CFO have evaluated the Trust's internal controls over financial reporting as at December 31, 2007 based on
the framework in "Internal Control – Integrated Framework" issued by the Committee of Sponsoring Organizations
of the Treadway Commission ("COSO") and have concluded they are sufficiently designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of the financial statements for external
purposes in accordance with GAAP. During the quarter ended December 31, 2007, there have been no changes to
the Trust's internal controls over financial reporting that have materially, or are reasonably likely to, materially affect
the internal controls over financial reporting.
Because of their inherent limitations, disclosure controls and procedures and internal controls over financial
reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived
or operated, can provide only reasonable, not absolute assurance, that the objectives of the control systems are
met.
Financial Reporting Update - Effective January 1, 2007, Bonavista adopted Canadian Institute of Chartered
Accountants ("CICA") Section 3855, "Financial Instrument Recognition and Measurement" Section 3865, "Hedges"
Section 1530, "Comprehensive Income", and Section 3861, "Financial Instruments – Disclosure and Presentation".
These standards have been adopted prospectively. See note 3 to the consolidated financial statements. On
December 1, 2006 the CICA issued three new accounting standards, Section 1535, "Capital Disclosures", Section
3862, "Financial Instruments – Disclosures" and Section 3863, "Financial Instruments – Presentation". These three
new standards will require additional disclosure in the Trust's financial statements commencing January 1, 2008.
The Trust will be required to adopt Section 3064 “Goodwill and Intangible Assets” on January 1, 2009. Canada’s
Accounting Standards Board confirmed January 1, 2011 as the effective date for complete convergence of Canadian
GAAP to International Financial Reporting Standards (“IFRS”). The Trust will continue to monitor and assess the
impact of the planned convergence of Canadian GAAP with IFRS.
Update on Regulatory Matters - On October 25, 2007, the Government of Alberta released its much anticipated
New Royalty Framework ("NRF"). The NRF was the government's response to a report issued September 18, 2007
by the Alberta Royalty Review Panel, which was commissioned by the Government of Alberta to perform a review
of the province's royalty system to, in their words, ensure that the people of Alberta were receiving their "Fair Share"
for the resources being extracted by the oil and gas industry. The full NRF is available at www.energy.gov.ab.ca.
The NRF is anticipated to take effect January 1, 2009, this will result in the Trust's royalty rates for the low value
sensitivity case to increase by less than one percent. Using GLJ's forecasted prices as at January 1, 2008 and a
10% discount rate will decrease the net present value of the Trust's reserves by less than two percent. Given the
recent strength in commodity prices, the NRF will significantly impact the net present value of the Trust's reserves,
however, at this time the full extent of the impact is not determinable, as the proposed framework has not been
enacted.
Environmental Matters - On April 26, 2007, the Federal Government released its Action Plan to Reduce
Greenhouse Gases and Air Pollution (the "Action Plan") also known as ecoACTION, which includes the Regulatory
Framework for Air Emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of
vehicles and the strengthening of energy standards for a number of energy-using products. Regarding large
industry and industry related projects, the Government's Action Plan intends to achieve the following: (i) an absolute
reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing mandatory targets; and (ii) air
pollution from industry is to be cut in half by 2015 by setting certain targets. New facilities using cleaner fuels and
technologies will have a grace period of three years. In order to facilitate the companies' compliance with the
Action Plan's requirements, while at the same time allowing them to be cost-effective, innovative and adopt cleaner
technologies, certain options are provided. These are: (i) in-house reductions; (ii) contributions to technology funds;
(iii) trading of emissions with below-target emission companies; (iv) offsets; and (v) access to Kyoto's Clean
Development Mechanism.
On March 10, 2008, the Government of Canada released "Turning the Corner – Taking Action to Fight Climate
Change" (the "Updated Action Plan") which provides some additional guidance with respect to the Government of
Canada's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. The Updated
Action Plan is primarily directed towards industrial emissions from certain specified industries including oil and
natural gas producers. The Updated Action Plan is intended to force industry to reduce greenhouse gas emissions
and to create a carbon emissions trading market, including an offset system, to provide incentive to reduce
greenhouse gas emissions and establish a market price for carbon. The Updated Action Plan provides for: (i)
mandatory reductions of 18% from the 2006 baseline starting in 2010 and by an additional 2% in subsequent years
for existing facilities; and (ii) new facilities built between 2004 and 2011 will have mandatory emissions standards
based upon clean fuel standards (natural gas) with a 2% reduction below the third years intensity levels. For the
upstream oil and natural gas industry the Updated Action Plan also provides for a company threshold of 10,000 boe
per day and a facility threshold of 3,000 tonnes of CO2.
On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management
Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. Bill 3 states that
facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emission intensity by
12% starting July 1, 2007; if such reduction is not initially possible the companies owning the large emitting facilities
will be required to pay $15 per tonne for every tonne above the 12% target. These payments will be deposited into
an Alberta-based technology fund that will be used to develop infrastructure to reduce emissions or to support
research into innovative climate change solutions. As an alternate option, large emitters can invest in projects
outside of their operations that reduce or offset emissions on their behalf, provided that these projects are based in
Alberta. Prior to investing, the offset reductions offered by a prospective operation, must be verified by a third party
to ensure that the emission reductions are real.
Given the evolving nature of the debate related to climate change and the control of greenhouse gases and
resulting requirements, at this time it is not possible to predict the impact of those requirements on Bonavista's
operations and financial condition although it is thought to be an immaterial amount.
Critical Accounting Estimates - The consolidated financial statements have been prepared in accordance with
Canadian GAAP. A summary of significant accounting policies are presented in note 2 of the Notes to the
Consolidated Financial Statements. Certain accounting policies are critical to understanding the financial condition
and results of operations of Bonavista.
a) Proved oil and natural gas reserves - Proved oil and natural gas reserves, as defined by the Canadian
Securities Administrators in National Instrument 51-101 with reference to the Canadian Oil and Natural Gas
Evaluation Handbook, are those reserves that can be estimated with a high degree of certainty to be
recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved
reserves.
An independent reserve evaluator using all available geological and reservoir data as well as historical
production data has prepared Bonavista’s oil and natural gas reserve estimates. 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 Trust’s development plans. The effect of changes in proved oil
and natural gas reserves on the financial results and position of the Trust is described below.
b) Depreciation, depletion and accretion expense - Bonavista uses the full cost method of accounting for
exploration and development activities whereby all costs associated with these activities are capitalized,
whether successful or not. The aggregate of capitalized costs, net of certain costs related to unproved
properties, and estimated future development costs is amortized using the unit-of-production method based
on estimated proved reserves. Changes in estimated proved reserves or future development costs have a
direct impact on depreciation and depletion expense.
Certain costs related to unproved properties and major development projects may be excluded from costs
subject to depletion until proved reserves have been determined or their value is impaired. These
properties are reviewed quarterly to determine if proved reserves should be assigned, at which point they
would be included in the depletion calculation, or for impairment, for which any write-down would be
charged to depreciation and depletion expense.
c) Full cost accounting ceiling test - The carrying value of property, plant and equipment is reviewed at
least annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable
by the future undiscounted cash flows. The cost recovery ceiling test is based on estimates of proved
reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions.
By their nature, these estimates are subject to measurement uncertainty and the impact on the financial
statements could be material. Any impairment would be charged as additional depletion and depreciation
expense.
d) Asset retirement obligations - The asset retirement obligations are estimated based on existing laws,
contracts or other policies. The fair value of the obligation is based on estimated future costs for
abandonment and reclamation discounted at a credit adjusted risk free rate. The costs are included in
property, plant and equipment and amortized over their useful life. The liability is adjusted each reporting
period to reflect the passage of time, with the accretion charged to earnings and for revisions to the
estimated future cash flows. By their nature, these estimates are subject to measurement uncertainty and
the impact on the financial statements could be material.
e)
Income taxes - The determination of the Trust's income and other tax liabilities requires interpretation of
complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and
potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may
differ significantly from that estimated and recorded.
Assessment of Business Risks
The following are the primary risks associated with the business of the Trust. These risks are similar to those
affecting others in the conventional energy trust sector. The Trust’s financial position, results of operations and
distributions to Unitholders are directly impacted by these factors and include:
1) operational risk associated with the production of oil and natural gas;
2) reserve risk in respect to the quantity and quality of recoverable reserves;
3) market risk relating to the availability of transportation systems to move the product to market;
4) commodity risk as crude oil and natural gas prices fluctuate due to market forces;
5)
financial risk such as volatility of the Canadian/US dollar exchange rate, interest rates and debt service
obligations;
6) potential risk of change in distributions;
7) environmental and safety risk associated with well operations and production facilities;
8) changing government regulations relating to royalty legislation, income tax laws, incentive programs,
operating practices and environmental protection relating to the oil and natural gas industry and the income
trust sector;
9) potential risk of liability to Unitholders resident in jurisdictions where there is no statutory protection for
Unitholders from liabilities of the Trust;
10) continued participation of the Trust’s lenders; and
11) counterparty risk with respect to non-performance by counterparties to financial derivative contracts.
The Trust seeks to mitigate these risks by:
1) acquiring mature properties with well established production trends to reduce technical uncertainty;
2) acquiring long life reserves to ensure more stable production and to reduce the economic risks associated
with commodity price cycles;
3) maintaining a low cost structure to maximize product netbacks and reduce impact of commodity price
cycles;
4) diversifying properties to mitigate individual property and well risk;
5) maintaining product mix to balance exposure to commodity prices;
6) conducting rigorous reviews of all property acquisitions;
7) monitoring pricing trends and developing a mix of contractual arrangements for the marketing of products
with creditworthy counterparties;
8) maintaining a hedging program to hedge commodity prices and foreign exchange currency rates with
creditworthy counterparties;
9) ensuring strong third party-operators for non-operated properties;
10) adhering to the Trust’s safety program and keeping abreast of current operating best practices;
11) keeping informed of proposed changes in regulations and laws to properly respond to and plan for the
effects that these changes may have on our operations;
12) carrying insurance to cover losses and business interruption; and
13) establishing and maintaining adequate cash resources to fund future abandonment and site restoration
costs.
OUTLOOK
As we progress into our eleventh year since restructuring the Company in 1997, we continue to benefit from all of
the same qualities that drove the success of Bonavista Petroleum Ltd. as a public company and an energy trust.
We apply similar proven principles and execute our strategy in a disciplined and cost-effective manner much the
same as in 1997 when we started on this mission of value creation. The foundation of this strategy is to actively
pursue low to medium risk drilling opportunities on the extensive undeveloped land base within our geographically
concentrated areas of operations. Despite a very active exploitation and development program over the past year,
the quality and quantity of our drilling opportunities continues to increase as we transition from 2007 into 2008. This
increase in inventory can be directly attributed to the detailed and tireless work of our talented technical team, who
possess a strong commitment and a solid understanding of the Western Canadian Sedimentary Basin. We also
continue to search for strategic acquisition opportunities where we can add value utilizing our own technical
expertise. This period of commodity price volatility and market uncertainty should benefit Bonavista in the near
future due to its proven track record of timely acquisitions and our strong balance sheet. In late 2007, we witnessed
acquisition prices decreasing to a level that compares favourably with our cost of adding reserves organically and
we acted on this by committing to a $167 million natural gas-weighted property acquisition, which was completed in
January 2008. Our prudent approach to capital investment has been very effective in the past and together with our
steadfast commitment to adding Unitholder value and attention to detail will continue to provide the foundation for
the future success of the Trust. Today our activity, efficiency, productivity and profitability remain among the
strongest levels in our ten year history.
As a result of completing this strategic property acquisition in the first quarter of 2008, Bonavista is pleased to
announce that its Board of Directors has approved an expanded operating and capital program for 2008. However,
in light of the current volatility in equity and commodity markets, Bonavista has decided to take a somewhat
conservative approach and proceed with a base capital budget of $400 to $420 million which includes no further
acquisition capital beyond the $167 million acquisition. The remainder of the capital program will be allocated to
Bonavista's exploration, exploitation and development programs which includes drilling approximately 200 to 220
wells on existing and recently acquired lands in our core regions. It is anticipated that the base capital program
should result in Bonavista's 2008 production volumes averaging approximately 54,000 to 54,500 boe per day. This
level of production factors in significant downtime anticipated in the second and third quarters, primarily due to two
major third party plant turnarounds. Assuming current commodity prices in the futures market are realized,
Bonavista's 2008 cashflow should increase to approximately $640 to $650 million. Bonavista has currently identified
over 680 drilling prospects on its current land base and may accelerate the drilling of some of these prospects in the
latter half of 2008, should market conditions warrant. In the interim, Bonavista will proceed prudently and
methodically with its stated drilling program in the first half of the year to allow for maximum financial flexibility and
remain opportunistic to further expand its capital program on additional acquisitions and/or drilling opportunities.
We are extremely proud of our achievements over our past ten years and are very excited about the growing
opportunities that exist for Bonavista in the future. We would like to thank our employees for their significant effort
and their continued enthusiasm and excitement as we pursue these opportunities. Despite the passage of
legislation in the Canadian House of Commons on the taxation of distributions from certain publicly traded
Canadian trusts and the introduction of the NRF by the Government of Alberta, Bonavista's value creation process
has not changed. Throughout many business cycles and changes in the business environment, Bonavista has
thrived. Our success is based on the consistent application of our core philosophy and operating strategies. Our
corporate structure may ultimately change by 2011 when the new tax laws are introduced but our proven strategy
will not change under this new tax regime nor the provincial government’s new royalty regime, as our team remains
dedicated to add Unitholder value in the oil and natural gas business, regardless of the changing landscape.
On behalf of the Board of Directors
Keith A. MacPhail
Chairman, President and
Chief Executive Officer
March 12, 2008
Calgary, Alberta
Ronald J. Poelzer
Executive Vice President and
Chief Financial Officer
MANAGEMENT’S REPORT
The preparation of the accompanying consolidated financial statements in accordance with accounting principles
generally accepted in Canada is the responsibility of management. Financial information contained elsewhere in
this Annual Report is consistent with that in the consolidated financial statements.
Management is responsible for the integrity and objectivity of the financial statements. Where necessary, the
financial statements include estimates, which are based on management’s informed judgments. Management has
established systems of internal controls, which are designed to provide reasonable assurance those assets, are
safeguarded from loss or unauthorized use and to produce reliable accounting records for the preparation of
financial information.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting
and internal control. It exercises its responsibilities primarily through the Audit Committee, all of whose members
are non-management directors. The Audit Committee has reviewed the consolidated financial statements with
management and the auditors and has reported to the Board of Directors, which have approved the consolidated
financial statements.
KPMG LLP are independent auditors appointed by Bonavista’s unitholders. The auditors have considered, for the
purposes of determining the nature, timing and extent of their audit procedures, the Trust’s internal controls and
have audited the consolidated financial statements in accordance with generally accepted auditing standards to
enable them to express an opinion on the fairness of the financial statements in accordance with Canadian
generally accepted accounting principles.
Keith A. MacPhail
President and
Chief Executive Officer
March 12, 2008
Calgary, Alberta
Ronald J. Poelzer
Executive Vice President and
Chief Financial Officer
AUDITORS' REPORT TO THE UNITHOLDERS
We have audited the consolidated balance sheets of Bonavista Energy Trust as at December 31, 2007 and 2006
and the consolidated statements of operations, comprehensive income and accumulated earnings and cash flows
for the years then ended. These financial statements are the responsibility of the Trust's management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards
require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position
of the Trust as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years
then ended in accordance with Canadian generally accepted accounting principles.
Chartered Accountants
Calgary, Canada
March 12, 2008
BONAVISTA ENERGY TRUST
Consolidated Balance Sheets
December 31,
(thousands)
Assets:
Current Assets:
Accounts receivable
Future income tax asset (note 10)
Oil and natural gas properties and equipment (note 6)
Goodwill
Liabilities and Unitholders’ Equity:
Current liabilities:
Accounts payable and accrued liabilities
Unrealized financial instruments (note 11)
Long-term debt and other obligations (note 7)
Convertible debentures (note 8)
Asset retirement obligations (note 5)
Future income taxes (note 10)
Unitholders’ equity:
Unitholders’ capital (note 9)
Exchangeable shares (note 9)
Contributed surplus (note 9)
Convertible debentures (note 8)
Accumulated earnings
Commitments (note 12)
2007
2006
$
112,226
$
116,251
13,517
125,743
-
116,251
2,074,993
1,910,359
41,321
41,321
$ 2,242,057
$ 2,067,931
$
91,034
$
122,376
45,058
136,092
712,654
48,830
116,893
166,621
850,631
74,710
9,369
1,054
-
122,376
514,169
51,170
96,324
153,639
834,625
75,121
4,973
1,117
125,203
214,417
1,060,967
1,130,253
$ 2,242,057
$ 2,067,931
See accompanying notes to the consolidated financial statements.
Approved on behalf of Bonavista Energy Trust, by Bonavista Petroleum Ltd. as administrator:
Ian S. Brown, Director
Michael M. Kanovsky, Director
BONAVISTA ENERGY TRUST
Consolidated Statements of Operations, Comprehensive Income and Accumulated Earnings
Years ended December 31,
(thousands, except per unit amounts)
Revenues:
Production
Royalties
Realized losses on financial instruments
Unrealized losses on financial instruments (note 11)
Expenses:
Operating
Transportation
General and administrative
Financing
Unit-based compensation
Depreciation, depletion and accretion
Income before taxes
Income taxes (reductions) (note 10)
Net income
Changes in comprehensive income, net of taxes
Comprehensive income
Accumulated earnings, beginning of year
Distributions declared
Accumulated earnings, end of year
Net income per unit – basic
Net income per unit – diluted
See accompanying notes to the consolidated financial statements.
2007
2006
$
911,346
$
910,079
(155,586)
(174,903)
755,760
(665)
(45,058)
710,037
735,176
(8,332)
-
726,844
162,371
152,087
41,397
13,335
35,209
7,351
232,722
492,385
217,652
(535)
218,187
(5,994)
212,193
214,417
40,065
11,229
26,960
4,890
215,558
450,789
276,055
(25,215)
301,270
-
301,270
237,163
(307,401)
(324,016)
$
125,203
$
214,417
$
$
2.07
2.06
$
2.95
$
2.90
BONAVISTA ENERGY TRUST
Consolidated Statements of Cash Flows
Years ended December 31,
(thousands, except per unit amounts)
Cash provided by (used in):
Operating Activities:
Net income
Items not requiring cash from operations:
Depreciation, depletion and accretion
Unit-based compensation
Unrealized losses on financial instruments
Future income taxes (reductions)
Asset retirement expenditures
Changes in non-cash working capital items
Financing Activities:
Issuance of equity, net of issue costs
Distributions
Changes in long-term debt
Changes in non-cash working capital items
Investing Activities:
Exploitation and development
Business acquisitions (note 4)
Property acquisitions
Property dispositions
Changes in non-cash working capital items
Change in cash
Cash, beginning of year
Cash, end of year
See accompanying notes to the consolidated financial statements.
2007
2006
$
218,187
$
301,270
232,722
7,351
45,058
(535)
(8,338)
(21,424)
215,558
4,890
-
(25,280)
(5,694)
(15,694)
473,021
475,050
8,144
(307,125)
200,331
(164)
5,936
(325,064)
168,521
121
(98,814)
(150,486)
(267,660)
(280,563)
-
(100,806)
2,110
(7,851)
(25,800)
(10,355)
365
(8,211)
(374,207)
(324,564)
-
-
-
$
$
-
-
-
BONAVISTA ENERGY TRUST
Notes to Consolidated Financial Statements
Years ended December 31, 2007 and 2006
1. Structure of the Trust and Basis of Presentation:
Bonavista Energy Trust (“Bonavista” or the “Trust”) is an open-ended unincorporated investment trust governed by the laws of
the Province of Alberta. The Trust was established on July 2, 2003 under a Plan of Arrangement entered into by the Trust,
Bonavista Petroleum Ltd. (“BPL”) and its subsidiaries and partnerships and NuVista Energy Ltd. (“NuVista”). Under the Plan of
Arrangement, a wholly-owned subsidiary of the Trust amalgamated with BPL and became the successor company. The Trust
has two significant subsidiaries in which it owns 100% of the common shares of BPL (excluding the exchangeable shares – see
note 9) and 100% of the units of Bonavista Trust (2003) (“BT”). The activities of these entities are financed through interest
bearing notes from the Trust and third party debt as described in the notes to the consolidated financial statements. The
business of the Trust is carried on through the entities owned by the subsidiaries of the Trust, Bonavista Petroleum, a general
partnership (“BP”) and Bonavista Energy Limited Partnership (“BELP”). The net income of the Trust is generated from interest
on notes advanced to its subsidiaries, royalty payments on oil and natural gas assets owned by BP, as well as any dividends or
distributions paid by its subsidiaries. The Trustee must declare payable to the Trust Unitholders all of the taxable income of the
Trust.
2. Significant accounting policies:
As determination of many assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these
consolidated financial statements requires the use of estimates and assumptions, which have been made using careful
judgement. In particular, the amounts recorded for depreciation, depletion and accretion of the oil and natural gas properties
and for asset retirement obligations are based on estimates of reserves and future costs. By their nature, these estimates, and
those related to future cash flows used to assess impairment, are subject to measurement uncertainty and the impact on the
financial statements of future periods could be material. In the opinion of management, these consolidated financial statements
have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting
policies summarized below:
a) Principles of consolidation:
The consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries, trusts and
proportionate share of its partnerships. All inter-entity transactions have been eliminated.
b) Oil and natural gas properties and equipment:
The Trust follows the full cost method of accounting, whereby all costs associated with the exploration for and development
of oil and natural gas reserves are capitalized in cost centres on a country-by-country basis. Such costs include land and
property acquisitions, geological and geophysical activities, drilling, well equipment and facilities. Gains or losses are not
recognized upon disposition of oil and natural gas properties unless crediting the proceeds against accumulated costs
would result in a change in the rate of depletion by 20% or more.
Costs capitalized in the cost centres, including well equipment, together with estimated future capital costs associated with
proven reserves, are depreciated and depleted using the unit-of-production method which is based on gross production
and estimated proven oil and natural gas reserves as determined by independent engineers. The cost of unproven
properties is excluded from the depreciation and depletion base. For purposes of the depreciation and depletion
calculations, oil and natural gas reserves are converted to a common unit of measure on the basis of their relative energy
content, being six thousand cubic feet of natural gas for one barrel of oil. Facilities are depreciated using the declining
balance method over their useful lives, which range from 12 to 15 years.
Oil and natural gas properties and equipment are evaluated in each reporting period to determine whether the carrying
amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying
amounts are assessed to be recoverable when the sum of the undiscounted future cash flows expected from the
production of proved reserves, the lower of cost and market of unproved properties and the cost of major development
projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an
impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted
cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved
properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected
future product prices and costs, and are discounted using a risk-free interest rate.
c) Joint operations:
A portion of Bonavista’s oil and natural gas operations are conducted jointly with others. Accordingly, the consolidated
financial statements reflect only Bonavista’s proportionate interest in such activities.
d) Goodwill:
Goodwill is tested for impairment on an annual basis in the fourth quarter of each year. If indications of impairment are
present, a loss would be charged to net income for the amount that the carrying value of goodwill exceeds its fair value.
e) Asset retirement obligations:
Bonavista records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets
in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability
there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost, which is
depleted on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect
the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows. Actual
costs incurred upon settlement of the obligations are charged against the liability.
f) Revenue recognition:
Revenues from the sale of oil and natural gas are recorded when title passes to an external party.
g) Financial instruments:
i) A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity
instrument to another entity. Upon initial recognition, all financial instruments, including all derivatives, are recognized
on the balance sheet at fair value. Subsequent measurement is then based on the financial instruments being classified
into one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other
liabilities. The Trust has designated its cash and cash equivalents and investments, other than equity investments, as
held for trading which are measured at fair value. Accounts receivable are classified as loans and receivables which are
measured at amortized cost. Accounts payable and accrued liabilities, distributions payable and bank debt are
classified as other liabilities which are measured at amortized cost, which is determined using the effective interest
method. The convertible debentures are classified as debt on the balance sheet with a portion of the proceeds allocated
to equity. The debt component has been measured at amortized cost.
ii) The Trust is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and
interest rates in the normal course of operations. A variety of derivative instruments may be used by the Trust to reduce
its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Trust does not use
these derivative instruments for trading or speculative purposes. The Trust considers all of these transactions to be
economic hedges, however, the majority of the Trust’s contracts do not qualify or have not been designated as hedges
for accounting purposes. As a result, all derivative contracts are classified as held for trading and are recorded on the
balance sheet at fair value, with changes in the fair value recognized in net income, unless specific hedge criteria are
met. The fair values of these derivative instruments are based on an estimate of the amounts that would have been
received or paid to settle these instruments prior to maturity given future market prices and other relevant factors.
Proceeds and costs realized from holding the derivative contracts are recognized in net income at the time each
transaction under a contract is settled. The Trust has elected to account for its physical delivery sales contracts, which
were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance
with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as non-
financial derivatives. The Trust nets all transaction costs incurred, in relation to the acquisition of a financial asset or
liability, against the related financial asset or liability. In accordance with this policy convertible debentures are recorded
net of issue costs and bank debt is presented net of deferred interest payments, with interest recognized in net income
on an effective interest basis.
h) Unit-based compensation:
Bonavista has an equity incentive plan, which is described in note 9. The trust unit incentive right compensation plan for
employees do not involve the direct award of trust units, or call for the settlement in cash or other assets. Bonavista uses
the fair value method for valuing the granting of trust unit incentive rights. Under this method, the compensation cost
attributable to all the trust unit rights granted is measured at fair value at the grant date and expensed over the vesting
period with a corresponding increase to contributed surplus. Upon the exercise of the trust unit rights, consideration
received together with the amount previously recognized in contributed surplus is recorded as an increase to Unitholders’
equity.
i) Restricted trust unit incentive plan:
Bonavista has established a Restricted Trust Unit Incentive Plan (the "RTU Plan") for our employees as described in
note 9. Vesting arrangements are within the discretion of our board of directors, but all awards will vest within three years
from the date of grant. On the vesting date the holder will receive either: (i) one trust unit; or (ii) the cash equivalent of one
trust unit for each unit award as well as all distributions made on trust units from the date of grant to and including the
vesting date at the discretion of the Trust. Trust units may be issued from treasury or purchased on the open market. The
Trust has not incorporated an estimated forfeiture rate for Restricted Trust Units that will not vest, rather the Trust accounts
for actual forfeitures as they occur.
j)
Income taxes:
Bonavista is a taxable entity under the Canadian Income Tax Act and until 2011 is taxable only on income that is not
distributed or distributable to its unitholders. Commencing in 2011, distributions paid to unitholders will not be deductible for
tax and Bonavista will be taxed on its income similar to corporations. The Trust follows the asset and liability method of
accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax
consequences attributable to differences between the amounts reported in the financial statements of BPL and its
subsidiaries and their respective tax basis, using substantively enacted income tax rates expected to be in effect when the
temporary differences are anticipated to reverse. In addition, income tax liabilities and assets are recognized for the
estimated tax consequences of temporary differences arising in the Trust that reverse after 2011. The effect of a change in
income tax rates on future income tax liabilities and assets is recognized in net income in the period that the change
occurs.
k) Per unit amounts:
Diluted per unit amounts reflect the potential dilution that could occur if securities or other contracts to issue trust units
were exercised or converted to trust units. The treasury stock method is used to determine the dilutive effect of unit
incentive rights and other dilutive instruments.
l) Comparative figures:
The comparative figures have been reclassified to reflect the current year presentation.
3. Changes in accounting policy:
Financial Instruments and Hedging Activities
Effective January 1, 2007, Bonavista adopted the Canadian Institute of Chartered Accountants (“CICA”) Section 3855, “Financial
Instruments – Recognition and Measurement”, Section 3865, “Hedges”, Section 1530, “Comprehensive Income”, and Section
3861, “Financial Instruments – Disclosure and Presentation”. Bonavista has adopted these standards prospectively and the
comparative consolidated financial statements have not been restated. Transition amounts have been recorded in accumulated
other comprehensive income.
As at January 1, 2007, the following adjustments were made to the consolidated balance sheet on adoption of the new
standards:
(thousands)
Accounts receivable – financial instruments
Future income taxes
Accumulated other comprehensive income
January 1, 2007
$
8,563
(2,569)
(5,994)
On December 1, 2006 the CICA issued three new accounting standards, Section 1535, "Capital Disclosures", Section 3862,
"Financial Instruments – Disclosures" and Section 3863, "Financial Instruments – Presentation". These three new standards will
require additional disclosure in the Trust's financial statements commencing January 1, 2008. The Trust will be required to adopt
Section 3064 “Goodwill and Intangible Assets” on January 1, 2009. Canada’s Accounting Standards Board confirmed
January 1, 2011 as the effective date for complete convergence of Canadian GAAP to International Financial Reporting
Standards (“IFRS”). The Trust will continue to monitor and assess the impact of the planned convergence of Canadian GAAP
with IFRS.
4. Business relationships:
Bonavista and NuVista are considered related as two directors of NuVista, one of whom is NuVista’s chairman, are directors and
officers of Bonavista and a director and an officer of NuVista are also officers of Bonavista.
Pursuant to the Plan of Arrangement , Bonavista entered into a Technical Services Agreement (“TSA”) with NuVista, whereby,
Bonavista received payment for certain technical and administrative services provided by it to NuVista on a cost recovery basis.
Effective January 1, 2007 the terms of the TSA were amended to reflect the reduced level of services provided by Bonavista and
subsequently on August 31, 2007 the TSA was terminated and replaced with a new services agreement that reflects the
remaining ongoing services that will be provided by Bonavista.
For the year ended December 31, 2007 NuVista paid Bonavista $1.4 million (2006 - $2.3 million) in fees relating to general and
administrative services provided to NuVista, in addition NuVista charged Bonavista management fees for a jointly owned
partnership totaling $1.4 million (2006 – nil). Bonavista also charged NuVista $975,000 ( 2006 – nil) for costs that are outside
the TSA relating to NuVista’s share of direct charges from third parties. As at December 31, 2007, the amount receivable from
NuVista was $703,000 (2006 - $2.7 million).
On June 1, 2006, Bonavista acquired oil and natural gas properties through a partnership for cash consideration of $25.8 million
and included the results of operations from the date of the acquisition. A director and an officer of Bonavista are related parties
of the vendor. Bonavista purchased these oil and natural gas properties through a series of transactions, with the properties
being acquired in an existing partnership owned approximately 24% by BP and 76% by NuVista Energy Ltd. In conjunction with
the acquisition, Bonavista recognized $800,000 of asset retirement obligations.
5. Asset retirement obligations:
The Trust’s asset retirement obligations result from net ownership interests in oil and natural gas assets including well sites,
gathering systems and processing facilities. For the year ended December 31, 2007 the Trust has changed its estimated costs to
reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods, resulting in an
increase of $16.0 million (2006 – nil). The Trust estimates the total undiscounted amount of expenditures required to settle its
asset retirement obligations is approximately $540.9 million (2006 – $475.2 million) which will be incurred over the next 51 years.
The majority of the costs will be incurred between 2010 and 2037. A credit-adjusted risk-free rate of 7.5% (2006 – 7.5%) and an
inflation rate of 2% (2006 – 2%) were used to calculate the fair value of the asset retirement obligations.
A reconciliation of the asset retirement obligations is provided below:
(thousands)
Balance, beginning of year
Accretion expense
Liabilities incurred
Liabilities acquired
Liabilities settled
Changes in assumptions
Balance, end of year
6. Oil and natural gas properties and equipment:
Years ended December 31,
2006
2007
$
96,324
$ 82,819
7,333
1,629
3,976
(8,338)
15,969
6,279
11,332
1,588
(5,694)
-
$ 116,893
$ 96,324
December 31, 2007
(thousands)
Oil and natural gas properties
Facilities
Office equipment
December 31, 2006
(thousands)
Oil and natural gas properties
Facilities
Office equipment
Cost
$
$
2,538,591
601,209
6,099
3,145,899
Cost
Accumulated
depreciation and
depletion
$
$
948,248
119,139
3,519
1,070,906
Accumulated
depreciation and
depletion
$
$
2,218,407
532,762
5,483
2,756,652
$
$
751,254
92,165
2,874
846,293
Net book value
$ 1,590,343
482,070
2,580
$ 2,074,993
Net book value
$ 1,467,153
440,597
2,609
$ 1,910,359
Unproved property costs of $159.3 million as at December 31, 2007 (2006 - $136.8 million) were excluded from the
depreciation and depletion calculation. Future development costs of $135.2 million (2006 - $123.2 million) were included in the
depreciation and depletion calculation.
Bonavista has calculated the ceiling test as of December 31, 2007. Based on the calculation, the present value of future net
revenues from the Trust’s proved reserves exceeds the carrying value of the Trust’s oil and natural gas properties and
equipment at December 31, 2007. The impairment test was calculated using the benchmark reference prices at January 1 for
the years 2008 to 2013 and adjusted for commodity differentials specific to Bonavista.
Benchmark Reference Price Forecasts:
Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
Remainder (1)
(1) Escalated at 2% per year thereafter
7. Long-term debt:
WTI Oil
(US$/bbl)
92.00
88.00
84.00
82.00
82.00
82.00
82.00
82.00
82.02
83.66
85.33
2.0%
AECO Gas
(Cdn$/mmbtu)
6.75
7.55
7.60
7.60
7.60
7.60
7.80
7.97
8.14
8.31
8.48
2.0%
USD/CAD
Exchange Rates
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
The Trust has a $1.0 billion credit facility with a syndicate of chartered banks. This facility is an unsecured, covenant-based,
extendible revolving facility and includes a $50 million working capital facility. The facility provides that advances may be made
by way of prime rate loans, bankers' acceptances and/or US dollar LIBOR advances. These advances bear interest at the
banks' prime rate and/or at money market rates plus a stamping fee. The facility is a three year revolving credit and may, at the
request of the Trust with the consent of the lenders, be extended on an annual basis. At present, no principal payments are
required under the credit facility until August 10, 2010.
Under the terms of the credit facility, the Trust has provided the covenant that its consolidated senior debt borrowing will not
exceed three times net income before interest, taxes and depreciation, depletion and accretion; consolidated total debt will not
exceed three and one half times consolidated net income before interest, taxes and depreciation, depletion and accretion; and
consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus consolidated unitholders' equity of
the Trust.
Financing expenses for the year ended December 31,2007 include interest on bank loans of $31.6 million (2006 - $22.4 million)
and convertible debentures of $3.6 million (2006 - $4.5 million). For the year ended December 31, 2007, Bonavista paid cash
interest of $35.4 million (2006 - $26.8 million). For the year ended December 31, 2007 the weighted average effective interest
rate was 5.3% (2006 – 4.8%)
8. Convertible debentures:
On January 29, 2004, Bonavista issued $100 million principal amount of 7.5% unsecured subordinated convertible debentures.
The issue costs related to this offering were $4.3 million. The debentures mature on June 30, 2009, pay interest semi-annually
and are convertible at the option of the holder into Trust Units of Bonavista at $23.00 per Trust Unit plus accrued and unpaid
interest. As at December 31, 2007 the principal amount outstanding was $7.8 million.
On December 31, 2004, Bonavista issued $135 million principal amount of 6.75% unsecured subordinated convertible
debentures. The issue costs related to the offering were $5.4 million. The debentures mature on June 30, 2010, pay interest
semi-annually and are convertible at the option of the holder into Trust Units of Bonavista at a price of $29.00 per Trust Unit,
plus accrued and unpaid interest. As at December 31, 2007 the principal amount outstanding was $43.3 million.
The debt component of the debentures has been recorded net of the fair value of the conversion feature and issue costs. The
fair value of the conversion feature of the debentures included in Unitholders’ equity at the date of issue was $4.7 million. The
issue costs are amortized to net income over the term of the obligation and the debt component of the obligation is adjusted for
the amortization as well as for the portion of issue costs relating to conversions. The debt portion is accreted over the term of
the obligation to the principal value on maturity with a corresponding charge to net income. The following table sets out the
convertible debenture activities to December 31, 2007:
Debt
Component
Equity
Component
(thousands)
Balance, December 31, 2005
Accretion
Issue expenses related to conversions to trust units
Amortization of issue expenses
Conversion to trust units
Balance, December 31, 2006
Accretion
Issue expenses related to conversions to trust units
Amortization of issue expenses
Conversion to trust units
$
$
87,866
115
629
745
(38,185)
51,170
75
29
702
(3,146)
Balance, December 31, 2007
$
48,830
$
1,892
-
-
-
(775)
1,117
-
-
-
(63)
1,054
9. Unitholders’ equity:
a) Authorized:
Unlimited number of voting trust units.
b)
Issued and outstanding:
(i) Trust units:
(thousands)
Balance, December 31, 2005
Issued on conversion of convertible debentures
Issued on conversion of exchangeable shares
Issued upon exercise of trust unit incentive rights
Issue costs, related to debenture conversions
Adjustment to equity component of debenture on conversion
Unit-based compensation
Balance, December 31, 2006
Issued on conversion of convertible debentures
Issued on conversion of exchangeable shares
Issued upon exercise of trust unit incentive rights
Issue costs, related to debenture conversions
Adjustment to equity component of debenture on conversion
Unit-based compensation
Balance, December 31, 2007
Number of
Units
80,288
1,491
2,526
534
-
-
-
84,839
125
110
683
-
-
-
85,757
$
Amount
769,629
38,185
17,249
5,936
(629)
775
3,480
834,625
3,146
411
8,144
(29)
63
4,271
$
850,631
Redemption right:
Unitholders may redeem their Trust Units at any time by delivering their Unit Certificates to the Trustee, together with a
properly completed notice requesting redemption. The redemption amount per Trust Unit will be the lesser of 90% of the
weighted average trading price of the Trust Units on the principal market on which they are traded for the 10 day period
after the Trust Units have been validly tendered for redemption and the “closing market price” of the Trust Units. The
redemption amount will be payable on the last day of the following calendar month. The “closing market price” will be the
closing price of the Trust Units on the principal market in which they are traded on the date on which they were validly
tendered for redemption, or, if there was no trade of the Trust Units on that date, the average of the last bid and ask prices
of the Trust Units on that date. Cash payments for Units tendered for redemption are limited to $250,000 per month with
redemption requests in excess of this amount, eligible to receive a note from BPL.
(ii) Contributed surplus:
(thousands)
Balance, December 31, 2005
Unit-based compensation expense
Unit-based compensation capitalized
Exercise of trust unit incentive rights
Balance, December 31, 2006
Unit-based compensation expense
Unit-based compensation capitalized
Exercise of trust unit incentive rights
Balance, December 31, 2007
(iii) Exchangeable shares:
$
Amount
2,456
4,890
1,107
(3,480)
4,973
7,351
1,316
(4,271)
$
9,369
Pursuant to the Plan of Arrangement, 15,999,999 exchangeable shares were authorized and issued. The exchangeable
shares of BPL are exchangeable only into trust units based on the exchange ratio, which is adjusted monthly, to reflect the
distribution paid on the trust units. As a result distributions are not paid on the exchangeable shares.
(thousands)
Balance, beginning of year
Exchanged for trust units
Balance, end of year
Years ended December 31,
2007
2006
Number
Amount
Number
Amount
12,297
(67)
$ 75,121
(411)
14,101
(1,804)
$ 92,370
(17,249)
12,230
$ 74,710
12,297
$ 75,121
Exchange ratio, end of year
1.72244
-
1.52443
-
Trust units issuable on exchange
21,066
$ 74,710
18,747
$ 75,121
On the tenth anniversary of the issuance of the Exchangeable Shares, subject to extension of such date by the Board of
Directors of BPL, the Exchangeable Shares will be redeemed for Trust Units at a price equal to the value of that number of
Trust Units based on the exchange ratio as at the last business day prior to the redemption date. BPL may redeem all but
not less than all of the outstanding Exchangeable Shares at any time when the aggregate number of issued and
outstanding Exchangeable Shares is less than 1,000,000. BPL will, at least 90 days prior to any redemption date, provide
the registered holders with written notice of the prospective redemption. The redemption price is equal to that described
previously.
c) Trust unit incentive rights plan:
The Trust has a unit incentive rights plan that allows the Trust to issue rights to acquire trust units to directors, officers,
employees and service providers. The Trust is authorized to issue up to 4,882,225 unit rights, however, the number of
trust units reserved for issuance upon exercise of the rights shall not at any time exceed 5% of the aggregate number of
issued and outstanding trust units of the Trust. Trust unit incentive right exercise prices are equal to the market price for
the trust units on the date that the unit rights are granted. If certain conditions are met, the exercise price per unit may be
calculated by deducting from the grant price the aggregate of all distributions, on a per unit basis, made by the Trust after
the grant date. The trust unit incentive rights granted under the plan vest over a four-year period and expire one year after
each vesting date.
Balance, December 31, 2005
Granted
Exercised
Cancelled
Reduction in exercise price
Balance, December 31, 2006
Granted
Exercised
Cancelled
Reduction in exercise price
Balance, December 31, 2007
Exercisable, December 31, 2007
The
following
December 31, 2007:
table summarizes
Number of Trust
Unit Incentive Rights
Weighted Average
Exercise
Price
2,937,525
1,514,100
(534,450)
(218,700)
-
3,698,475
894,900
(682,575)
(184,675)
-
3,726,125
925,750
21.86
33.92
(11.11)
(26.34)
(3.42)
24.67
30.70
(11.93)
(27.94)
(3.53)
$
$
24.76
19.26
trust unit
incentive rights outstanding and exercisable under
the plan at
Range of
exercise
prices
$
1.00 – 15.00
15.00 – 30.00
30.01 – 32.00
$
1.00 – 32.00
Number
outstanding
at year-end
353,050
3,294,075
79,000
3,726,125
d) Unit-based compensation:
Trust Unit Incentive
Rights Outstanding
Weighted
average
remaining
contractual
life
Trust Unit Incentive
Rights Exercisable
Weighted
average
exercise
price
Number
exercisable at
year-end
Weighted
average
exercise
price
0.9
3.4
3.1
3.2
$
4.59
26.77
31.05
$ 24.76
275,450
629,975
20,325
925,750
$
3.09
25.95
31.05
$
19.26
The Trust uses the fair value based method for the determination of the unit-based compensation costs. The fair value of
each incentive right granted was estimated on the date of grant using the modified Black-Scholes option-pricing model. In
the pricing model, the risk free interest was 3.5% (2006 – 3.5%); volatility of 31% (2006 - 25%); a forfeiture rate of 10%
(2006 - 10%) and an expected life of 4.5 years. The fair value of the options granted in 2007 averages $8.44
(2006 - $7.96) per incentive right.
e) Restricted trust unit incentive plan:
The Trust has a Restricted Trust Unit Incentive Plan that allows the Trust to award trust units to directors, officers,
employees and service providers. The number of restricted trust units available under the plan shall be limited to 5% of the
aggregate number of issued and outstanding units of the Trust. Vesting arrangements are within the discretion of our
board of directors, but all awards will vest within three years from the date of grant. On the vesting date the holder will
receive either: (i) one trust unit; or (ii) the cash equivalent of one trust unit for each unit award as well as all distributions
made on trust units from the date of grant to and including the vesting date at the discretion of the Trust. Trust units may
be issued from treasury or purchased on the open market.
The following table summarizes the restricted trust unit's outstanding under the plan at December 31, 2007:
Balance, December 31, 2006
Granted
Forfeited
Balance, December 31, 2007
-
168,844
(9,105)
159,739
For the year ended December 31, 2007, the Trust expensed $2.2 million (2006 – nil) relating to the Restricted Trust Unit
Incentive Plan.
f) Per unit amounts:
The following table summarizes the weighted average trust units, exchangeable shares and convertible debentures used in
calculating net income per trust unit:
Years ended December 31,
(thousands)
Trust units
Exchangeable shares converted at the exchange ratio
Basic equivalent trust units
Convertible debentures
Trust unit incentive rights
Diluted equivalent trust units
2007
85,350
20,193
105,543
1,891
641
108,075
2006
83,556
18,600
102,156
2,389
1,070
105,615
For the purposes of calculating net income per trust unit on a diluted basis, the net income has been increased by
$4.4 million (2006 – $5.4 million) with respect to the accretion, amortization and interest expense on the convertible
debentures. For the year ended December 31, 2007 the Trust excluded 1.7 million (2006 – 789,000) weighted average
trust unit incentive rights from the diluted unit calculation as they are anti-dilutive.
g) Accumulated other comprehensive income:
The following table summarizes the amounts recognized on adoption of the new accounting standards for financial
instruments and also the amortization of the amount recognized in accumulated other income on January 1, 2007:
(thousands)
Balance, January 1, 2007
Transition adjustment for discontinuance of hedge accounting, net of taxes of $2,569
Reclassification to net income during the year, net of taxes of $2,569
Balance, December 31, 2007
10. Income taxes:
$
$
-
5,994
(5,994)
-
The provision for income tax differs from the result which would have been obtained by applying the combined Federal
and Provincial income tax rates to net income before taxes. This difference results from the following items:
Expected tax rate
(thousands)
Expected tax expense
Effect of change in tax rate
Distributions to unitholders
SIFT tax, net of tax rate reduction
Other
Provision for income taxes (reductions)
The provision for income taxes consists of:
Current
Future (reduction)
Provision for income taxes (reductions)
(thousands)
Oil and natural gas properties
Facilities
Asset retirement obligations
Unrealized financial instruments
Future income taxes
The significant components of future income tax assets and liabilities as at December 31 are:
For the year ended December 31, 2007 Bonavista paid tax installments of nil (2006 - $785,000).
Years ended December 31,
2006
2007
32.6%
35.5%
$
70,955
$
98,000
(10,872)
(99,673)
36,444
2,611
(535)
-
(535)
(535)
$
$
$
$
2007
156,540
38,599
(28,518)
(13,517)
(11,839)
(113,481)
-
2,105
(25,215)
65
(25,280)
(25,215)
2006
146,023
36,513
(28,897)
-
$
$
$
$
$
153,104
$
153,639
11. Financial instrument activities:
a) Balance sheet financial instruments:
Bonavista's financial instruments recognized in the Consolidated Balance Sheet consist of accounts receivable, accounts
payable, long-term debt, and other long-term obligations. The market deficit of the Trust’s derivative financial instruments
is $45.1 million. Unless otherwise noted, carrying values reflect the current fair value of the Trust’s financial instruments.
The estimated fair values of recognized financial instruments have been determined based on Bonavista's assessment of
available market information and appropriate methodologies, or through comparisons to similar instruments. The fair
market value of the convertible debentures as at December 31, 2007 is $52.5 million.
b) Commodity price contracts:
i) Financial instruments:
As at December 31, 2007, the Trust has hedged by way of costless collars to sell natural gas (gjs/d) and crude oil (bbls/d)
as follows:
Volume
Average Price
Term
5,000 gjs/d
5,000 gjs/d
7,000 bbls/d
1,000 bbls/d
2,000 bbls/d
- CDN$ 10.55 – AECO
- CDN$ 9.00 – AECO
- US$ 78.58 – WTI
CDN$ 7.50
CDN$ 7.00
US$ 65.43
CDN$ 49.00 - CDN$ 57.00 – Bow River
US$ 65.00
- US$ 80.50 – WTI
January 1, 2008 – March 31, 2008
April 1, 2008 – October 31, 2008
January 1, 2008 – December 31, 2008
January 1, 2008 – December 31, 2008
January 1, 2009 – March 31, 2009
As at December 31, 2007, the market deficit of these derivative financial instruments was approximately $45.1 million.
ii) Physical purchase contracts:
As at December 31, 2007, the Trust has entered into direct sale costless collars to sell natural gas as follows:
Volume
Average Price (CDN$ - AECO)
Term
20,000 gjs/d
$ 7.75 - $ 10.53
January 1, 2008 – March 31, 2008
c) Credit risk:
Portions of the Trust’s accounts receivable are with joint operating partners in the oil and natural gas industry and are
subject to normal industry credit risks. Purchasers of the Trust’s oil and natural gas products are subject to an internal
credit review designed to mitigate the risk of non-payment.
d)
Interest rate risk:
The Trust is exposed to interest rate risk to the extent that changes in market interest rates will impact the Trust’s bank
debt which is subject to a floating interest rate.
e) Foreign currency:
While substantially all of the Trust’s sales are denominated in Canadian dollars, the market prices in Canada for oil and
natural gas are impacted by changes in the exchange rate between Canadian and United States dollar.
12. Commitments:
The following is a summary of the Trust’s commitments as at December 31, 2007:
Total
2008
2009
2010
2011
2012 and
thereafter
Payments Due by Period
(thousands)
Transportation expenses
Office premises
$ 24,706
4,762
$ 12,657
1,527
$ 8,127
1,527
$ 1,324
1,412
$
953
296
$ 1,645
-
Total commitments
$ 29,468
$ 14,184
$ 9,654
$ 2,736
$ 1,249
$ 1,645
13. Subsequent events:
a) Property acquisition:
On January 14, 2008, the Trust completed the acquisition of producing and undeveloped oil and natural gas properties in
the Willesden Green area of our South Central Alberta core region and the Fireweed area located in our Northeast British
Columbia core region for a net purchase price of $167 million.
b) Financial instrument activities:
Subsequent to December 31, 2007, the Trust has entered into the following commodity contracts:
i) Financial instruments:
The Trust has hedged by way of costless collars to sell natural gas (gjs/d) and crude oil (bbls/d) as follows:
Volume
Average Price
Term
20,000 gjs/d
2,000 bbls/d
1,000 bbls/d
CDN$ 7.38 - CDN$ 8.46 – AECO
CDN$ 61.00 - CDN$ 71.75 – Bow River
US$ 85.00
- US$ 105.60 – WTI
April 1, 2008 – October 31, 2008
April 1, 2008 – December 31, 2008
January 1, 2009 – December 31, 2009
ii) Physical purchase contracts:
The Trust has entered into direct sale costless collars to sell natural gas as follows:
Volume
Average Price (CDN$ - AECO)
Term
45,000 gjs/d
25,000 gjs/d
$ 7.19 - $ 8.36
$ 7.65 - $ 9.65
April 1, 2008 – October 31, 2008
November 1, 2008 – March 31, 2009
CORPORATE INFORMATION
DIRECTORS
Keith A. MacPhail,
Chairman, President and CEO
Ian S. Brown,
Independent Businessman
Michael M. Kanovsky,
Sky Energy Corporation
Harry L. Knutson,
Nova Bancorp Inc.
Margaret A. McKenzie,
Range Royalty Management Ltd.
Ronald J. Poelzer,
Executive Vice President and CFO
Christopher P. Slubicki,
Independent Businessman
Walter C. Yeates,
Independent Businessman
OFFICERS
Keith A. MacPhail,
Chairman, President and CEO
Ronald J. Poelzer,
Executive Vice President and CFO
Glenn A. Hamilton,
Senior Vice President
John A. Curkan,
Vice President, Marketing
Orest G. Humeniuk,
Vice President, Land
Dean M. Kobelka,
Vice President and Controller
Thomas J. Mullane,
Vice President, Engineering
Lynda J. Robinson,
Vice President, Human Resources and Administration
Jason E. Skehar,
Vice President, Production
Hank R. Spence,
Vice President, Operations
Johannes H. Thiessen,
Vice President, Exploration
Grant A. Zawalsky,
Corporate Secretary
FOR FURTHER INFORMATION CONTACT:
Keith A. MacPhail
President and CEO
(403) 213-4315
or
AUDITORS
KPMG LLP
Chartered Accountants
Calgary, Alberta
BANKERS
Canadian Imperial Bank of Commerce
Bank of Montreal
Royal Bank of Canada
The Bank of Nova Scotia
The Toronto-Dominion Bank
Alberta Treasury Branches
BNP Paribas (Canada)
National Bank of Canada
Union Bank of California, N.A. (Canada Branch)
Fortis Capital (Canada)
HSBC Bank Canada
Société Générale (Canada Branch)
Sumitomo Mitsui Banking Corporation of Canada
Calgary, Alberta
ENGINEERING CONSULTANTS
GLJ Petroleum Consultants Ltd.
Ryder Scott Company Canada
Calgary, Alberta
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP
Calgary, Alberta
REGISTRAR AND TRANSFER AGENT
Valiant Trust Company
Calgary, Alberta
STOCK EXCHANGE LISTING
Toronto Stock Exchange
Trading Symbol “BNP.UN”, “BNP.DB” and “BNP.DB.A”
HEAD OFFICE
700, 311 – 6 t h Avenue SW
Calgary, Alberta T2P 3H2
Telephone: (403) 213-4300
(403) 262-5184
Facsimile:
inv_rel@bonavistaenergy.com
Email:
www.bonavistaenergy.com
Website:
Ronald J. Poelzer
Executive Vice President and CFO
(403) 213-4308