Berens Energy Ltd. releases financial results for the first quarter ended March 31, 2008
Tue May 13, 9:01 AMSymbol: BEN - TSX
CALGARY, May 13 /CNW/ -
FINANCIAL AND OPERATING HIGHLIGHTS
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($ Cdn thousands, Three months
except as noted) ended March 31,
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2008 2007 % Change
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Sales volume
Natural gas (mcf/day) 19,104 18,705 2%
Oil and ngls (bbl/day) 628 499 26%
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boe/day (6 to 1) 3,812 3,617 5%
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Revenue net of royalties 14,516 11,780 23%
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Net income (loss) (5,413) (3,044) (78%)
Per share (basic and diluted) $ (0.06) $ (0.03)
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Funds from operations(1) 9,269 6,973 33%
Per share (basic and diluted)(1) $ 0.10 $ 0.07
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Capital costs
Exploration and development 10,168 17,078 (50%)
Land and seismic 1,414 1,071 32%
Other 2 12
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Total 11,586 18,161 (45%)
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Net wells completed (No.) 5 7
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Net working capital deficit - excluding
unrealized hedging losses (61,996) (66,896) (7%)
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Net working capital deficit - including
unrealized hedging losses (69,711) (67,468) 3%
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Shares outstanding
End of period (000's) 93,172 92,947 -
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Note:
(1) Non-GAAP measure - represents cash flow from operating activities
before non-cash working capital changes. Refer to Management's
Discussion and Analysis for discussion of this measure.
First Quarter 2008 Operating Highlights
Berens is pleased to provide our first quarter results that demonstrate
ongoing drilling success, continued strong capital efficiency, stable
operating costs and increased cash flow:
- Drilling - Drilling during the first quarter saw a continuation of
our 2007 success.
- At Pembina, year-to-date drilling has been 100% successful on
6 (3.8 net) completed in the quarter. We have now drilled
32 consecutive successful wells in Pembina.
- In Deep Basin, we drilled 2 (0.5 net) successful wells out of 3 in
the first quarter. Both wells will be brought on stream later in
the year.
- Our finding and development cost efficiency continued from our
strong results in 2007 with internally estimated finding and
development costs in the $12.00 range.
- Production - Q1 2008 production averaged 3,812 boe/d, up 5% over Q1
2007. Current production is over 4,000 boe/d as production from Q1
Pembina drilling was brought on stream late in the quarter. Current
2008 exit guidance is 4,100 to 4,300 boe/d, however, with stronger
natural gas prices and cash flow, additional capital spending is
being considered that would improve the exit rate expectations.
- Production Costs - Costs averaged $8.30 per boe in Q1 2008, up 2%
compared to $8.12 per boe in Q1 2007. Operating expenses are
typically higher in the first quarter due to winter conditions. We
expect operating costs to return to the $7.50 range for the remainder
of the year.
- Funds from Operations - Funds from operations for Q1 2008 were
$9.3 million ($0.10 per share), up 33% compared to Q1 2007 funds from
operations of $7.0 million ($0.07 per share). Higher production,
stronger commodity prices and stable per unit operating costs
contributed to the increase. For the quarter ended March 31, 2008,
the ratio of debt to annualized funds from operation declined to
1.7 times.
- Land - Berens' total undeveloped land currently stands at 90,000 net
acres, down from 100,000 at the end of 2007. The undeveloped land
base increased in quality as 11 (7.5 net) sections of undeveloped
land has been added in Pembina, our key growth area, while reductions
occurred due to drilling activity and expiries primarily in Lanfine.
We continue to have approximately 100 locations in our drilling
inventory.
Message to the shareholders
The first quarter of 2008 picked up right where we left off in 2007. Drilling success in Pembina continued with 32 consecutive successful wells to date. Reserves and production per well continue to be on target. We continue to exploit our competitive advantage in the area based on intensive integration of technology, geology and geophysics. Drilling and completion costs are down and operating costs remain low. Costs remain an ongoing focus for our team as there is risk that increased industry activity will accompany improved commodity prices. Natural gas prices have rallied and there appears to be some staying power to the higher prices.
So far in 2008 we are 6 for 6 in Pembina and 2 for 3 in our exploratory efforts in Deep Basin for an overall success rate of 89 percent. We have an extensive inventory of 100 drilling prospects across our three core areas, all on our existing land base. Most of our prospects in Pembina and Lanfine are seismically defined and as such are repeatable with low risk. With our discipline on costs and the extensive drilling inventory, we remain confident in being able to continue to generate finding and development costs comparable to 2007. Stronger commodity prices will provide increased cash flow that will be used to reduce debt and expand exploration drilling for the balance of 2008. The technical team is assessing the possibility of drilling horizontal wells in the Pembina area to assess new multi-frac completion technologies that may provide further upside to our drilling program. We continue to add land in Pembina, with an additional 11 sections added already in 2008, building further our strong land position in this key growth area.
There is optimism in our industry that natural gas price strength is sustainable in 2008 and beyond. With the natural gas price strength we are seeing it is time for Berens to expand its activities and get more aggressive with growth initiatives.
Sincerely,
Daniel F. Botterill
President & Chief Executive Officer
Berens Energy Ltd.
First Quarter 2008
Management's Discussion and Analysis ("MD&A")
May 12, 2008
OVERVIEW
Berens Energy Ltd. ("Berens" or the "Company") is a full cycle oil and natural gas exploration and production company with a concentrated production and land base in the Eastern Alberta, Pembina and Deep Basin regions of Alberta.
All calculations converting natural gas to crude oil equivalent have been made using a ratio of six thousand cubic feet (six "mcf") of natural gas to one barrel of crude equivalent. Barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf of natural gas to one barrel of crude oil equivalent is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
The following discussion of financial position and results of operations should be read in conjunction with the Company's December 31, 2007 audited financial statements and notes thereto and the unaudited March 31, 2008 interim financial statements and notes thereto. This MD&A was prepared using information that is current as of May 12, 2008 unless otherwise noted.
STRATEGY AND OBJECTIVES
The 2008 $30 million capital program is funded by cash flow based on an assumed natural gas price of $7.00 per mcf. This program is expected to generate 2008 exit production rates of 4,100 to 4,300 boe/d, about 10 percent higher than the fourth quarter 2007 average. With stronger natural gas prices it is expected that the capital program will be increased but still kept within cash flow.
Longer term value is achieved by adding oil and natural gas reserves at low cost. The Company expects to replace 2008 production 1.5 times with new reserves at finding and development costs below $15.00/boe. Operating and corporate netbacks are expected to be $31.00 per boe and $25.00 per boe respectively assuming a $8.00 per mcf price for natural gas and $100.00 per barrel for oil. Resulting recycle ratios based on the above factors are over 2.0 times on an operating netback basis and 1.7 times based on the corporate netback. Both of these measures will deliver long term added value.
FORWARD LOOKING INFORMATION
This MD&A contains forward looking information within the meaning of applicable securities laws. Forward looking statements may include estimates, plans, expectations, forecasts, guidance or other statements that are not statements of fact. Berens believes the expectations reflected in such forward looking statements are reasonable. However no assurance can be given that such expectations will prove to be correct. These statements are subject to certain risks and uncertainties and may be based on assumptions where actual results could differ materially from those anticipated or implied in the forward looking statements. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate and interest rate fluctuations, availability of services and supplies, market competition, uncertainties in the estimates of reserves, the timing of development expenditures, production levels and the timing of achieving such levels, the Company's ability to replace and increase oil and gas reserves, the sources and adequacy of funding for capital investments, future growth prospects and current and expected financial requirements of the Company, the cost of future abandonment and site restoration, the Company's ability to enter into or renew leases, the Company's ability to secure adequate product transportation, changes in environmental and other regulations and general economic conditions. These statements are as of the date of this MD&A and the Company does not undertake an obligation to update its forward looking statements except as required by law.
Additional information on the Company can be found on the SEDAR website at www.sedar.com.
QUARTERLY INFORMATION
2008
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($000's except as noted) Q1
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Sales volumes:
Natural gas (mcf/day) 19,104
Oil and natural gas liquids (bbl/day) 628
Barrels of oil equivalent 3,812
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Financial:
Net revenue 14,517
Net (loss) (5,413)
per share - basic ($/share) $(0.06)
per share - diluted ($/share) $(0.06)
Capital costs 11,586
Shares outstanding (000's) 93,172
Bank debt 58,500
Working capital (deficit)
including bank debt (69,711)
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Per unit information:
Natural gas price ($/mcf) $8.12
Oil and liquids price ($/barrel) $81.76
Oil equivalent price ($/boe) $54.16
Operating netback ($/boe) $32.36
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Net wells completed: (No.)
Natural gas 5
Oil -
Dry -
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Total 5
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2007
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($000's except as noted) Q4 Q3 Q2 Q1
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Sales volumes:
Natural gas (mcf/day) 19,018 18,288 19,919 18,705
Oil and natural gas
liquids (bbl/day) 626 570 560 499
Barrels of oil equivalent 3,796 3,618 3,880 3,617
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Financial:
Net revenue 13,214 11,864 12,739 11,793
Net (loss) (680) (23,157) (557) (3,043)
per share - basic
($/share) $(0.01) $(0.25) $(0.00) $(0.03)
per share - diluted
($/share) $(0.01) $(0.25) $(0.00) $(0.03)
Capital costs 6,718 8,541 6,208 18,329
Shares outstanding (000's) 93,172 93,172 93,172 92,947
Bank debt 53,900 50,800 62,700 59,980
Working capital (deficit)
including bank debt (59,516) (59,300) (64,644) (68,502)
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Per unit information:
Natural gas price ($/mcf) $6.52 $5.94 $7.60 $7.75
Oil and liquids price
($/barrel) $71.66 $64.11 $58.98 $55.24
Oil equivalent price
($/boe) $44.48 $40.14 $47.51 $47.72
Operating netback ($/boe) $26.85 $22.95 $27.88 $27.16
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Net wells completed: (No.)
Natural gas 3 5 1 5
Oil - 2 - -
Dry - 1 - 1
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Total 3 8 1 6
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2006
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($000's except as noted) Q4 Q3 Q2
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Sales volumes:
Natural gas (mcf/day) 18,440 17,355 17,224
Oil and natural gas
liquids (bbl/day) 483 479 494
Barrels of oil equivalent 3,556 3,372 3,364
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Financial:
Net revenue 11,213 9,536 9,846
Net (loss) (21,951) (2,662) (1,606)
per share - basic
($/share) $(0.24) $(0.03) $(0.02)
per share - diluted
($/share) $(0.24) $(0.03) $(0.02)
Capital costs 12,811 9,746 15,234
Shares outstanding (000's) 92,947 86,447 86,447
Bank debt 50,080 52,780 49,580
Working capital (deficit)
including bank debt (56,271) (61,783) (57,789)
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Per unit information:
Natural gas price ($/mcf) $7.13 $5.91 $6.28
Oil and liquids price
($/barrel) $51.54 $62.07 $64.27
Oil equivalent price
($/boe) $43.96 $39.24 $41.59
Operating netback ($/boe) $24.24 $21.54 $22.87
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Net wells completed: (No.)
Natural gas 7 3 9
Oil - - -
Dry 1 1 1
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Total 8 4 10
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Ongoing drilling has delivered the production increases for the past eight quarters with the decline in production for the third quarter of 2007 caused mainly by the disposition of Marten Hills production of 250 boe per day. There have been no other material acquisitions or dispositions.
RESULTS OF OPERATIONS
Production Volume
Volume averaged 3,812 boe/d for the quarter ended March 31, 2008, up five percent compared to 3,617 boe/d for the quarter ended March 31, 2007. Natural gas represented 84 percent of production in the first quarter of 2008 with the remaining production being 15 percent light oil and natural gas liquids and one percent conventional heavy oil.
High drilling success rates, primarily in Pembina combined with strong average production results continued in the first quarter of 2008 mirroring the success that was achieved during 2007. A total of nine wells (4.7 net) were completed in the quarter with six successful (3.8 net) natural gas wells in Pembina and two (0.5 net) successful natural gas wells in Deep Basin with one (0.4 net) unsuccessful well in Deep Basin. As at March 31, 2008 the Deep Basin wells had not been tied in and two (1.5 net) Pembina wells remained to be tied in. An integrated approach combining petrophysics, geophysics and geological mapping has enabled the Company to target specific trends that have been drilled at high success rates and strong economic returns over the past 18 months. Significant production was brought in late in the first quarter which is expected to support further volume increases in the second quarter of 2008 when drilling activity will be low due to spring break-up.
Production Revenue
Natural gas prices averaged $8.12 per mcf for the quarter ended March 31, 2008, up five percent compared to $7.75 per mcf in the quarter ended March 31, 2007. Oil and liquids prices averaged $83.85 and $80.77 per barrel respectively for the quarter ended March 31, 2008 for a blended price of $81.76 per barrel, up 48 percent from the quarter ended March 31, 2007 blended oil and liquids price of $55.24 per barrel. On a boe basis, prices averaged $54.16 in the quarter ended March 31, 2008, up 13 percent compared to $47.72 per boe in the quarter ended March 31, 2007. Revenue before results from hedging was up 22 percent in the quarter ended March 31, 2008 compared to the quarter ended March 31, 2007 as both volume and prices increased. An additional $0.40 per boe was realized from hedging gains during the quarter ended March 31, 2008 for total revenue of $54.56 per boe compared to $0.04 per boe realized on hedging gains in the quarter ended March 31, 2007.
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Volumes and prices Quarter ended
March 31,
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2008 2007 Change
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Production revenue ($000's) 18,792 15,544 21%
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Production volume
Natural gas (mcf/d) 19,104 18,705 2%
Oil and liquids (bbl/d) 628 499 26%
BOE (bbl/d) 3,812 3,617 5%
Prices
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Natural gas ($/mcf) 8.12 7.75 5%
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Oil and liquids ($/bbl) 81.76 55.24 48%
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BOE ($/boe) 54.16 47.72 13%
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BOE ($/boe including hedging) 54.56 47.76 14%
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Royalties
Royalties averaged 23 percent of revenue for the quarter ended March 31, 2008 compared to 24 percent for the quarter ended March 31, 2007. Royalties have trended lower on a percent of revenue basis as more wells are drilled on owned and earned lands compared to earlier periods when a higher percentage of wells were drilled under farm-in arrangements that provided for overriding royalties to the farmor.
Royalty expense of $4.3 million was recorded in the quarter ended March 31, 2008, up 14 percent compared to the quarter ended March 31, 2007 due to higher production volume offset by lower percentage royalty rates.
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Royalties Quarter ended
March 31,
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2008 2007 Change
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Royalty expense ($000's) 4,276 3,764 14%
Royalty cost per boe $12.33 $11.56 7%
Royalty cost as a percent of revenue 23% 24% (4%)
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Production Expenses
Production expenses were $8.30 per boe in the quarter ended March 31, 2008, up two percent compared to $8.12 per boe in the quarter ended March 31, 2007. Costs in 2008 have been kept stable on a per unit basis during an inflationary period as production has increased and vigilance on costs remains a key objective. Operating costs tend to be higher in the winter months due to added costs for certain chemicals and processes to keep wells from freezing and added costs to access wells due to cold weather and snow. With ongoing volume increases and cost management, it is expected per unit operating expenses will be in the $7.50 per boe range for the remainder of the year.
Production expenses for the quarter ended March 31, 2008 were $2.9 million, up nine percent compared to the quarter ended March 31, 2007 due to higher volumes and higher per unit costs.
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Production expenses Quarter ended
March 31,
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2008 2007 Change
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Production expenses ($000's) 2,880 2,643 9%
Production expenses per boe $8.30 $8.12 2%
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Transportation costs increased 42 percent in the quarter ended March 31, 2008 compared to the quarter ended March 31, 2007 due to higher volume and higher per unit costs due to increased transportation rates on major natural gas trunk pipelines.
Operating Netback(1)
Operating netback represents the margin realized by the production and sale of petroleum and natural gas exclusive of results from hedging. First quarter 2008 operating netbacks improved due to higher per boe prices, lower percentage royalty costs and stable operating costs.
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Quarterly Operating Netbacks Quarter ended
($'s per boe) March 31,
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2008 2007 Change
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Sales price 54.16 47.72 13%
Less:
Royalties 12.33 11.56 7%
Production expenses 8.30 8.12 2%
Transportation charges 1.17 0.87 34%
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Operating netback 32.36 27.16 19%
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Operating netback including hedging 32.76 27.20 20%
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(1) non-GAAP measure - refer to discussion on non-GAAP measures below.
General and Administrative Expenses
For the quarter ended March 31, 2008 general and administrative ("G&A") expenses were $1.2 million, up 29 percent compared to the quarter ended March 31, 2007. G&A charged to partners on capital spending in the first quarter of 2008 was lower than in the first quarter of 2007 as the total level of capital spending was lower in the 2008 period and wells were being drilled at higher average working interest. Stock based compensation was higher in the first quarter of 2008 compared to the first quarter of 2007 as total outstanding options increased.
On a per unit basis, for the quarter ended March 31, 2008 per unit G&A costs were $4.09 per boe, up 17 percent from $3.49 per boe for the quarter ended March 31, 2007 as volume increases partially offset the dollar increase in costs for the per unit calculation. There were no general and administrative costs capitalized for the quarters ended March 31, 2008 or 2007.
Staff levels are expected to remain fairly constant in 2008. Per unit general and administrative costs are expected to decline as production levels increase.
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General and administrative expenses Quarter ended
March 31,
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2008 2007 Change
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G&A expenses ($000's) 1,199 933 29%
Stock based compensation 219 203 8%
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Total 1,418 1,136 28%
G&A expenses per boe $4.09 $3.49 17%
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Interest Expense
For the quarter ended March 31, 2008 interest expense was $0.9 million compared to $1.0 million for the quarter ended March 31, 2007. Average amounts drawn on the bank operating line in the first quarter of 2008 were slightly higher than in the first quarter of 2007 the effect of which was more than offset by lower interest rates.
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Interest Expense Quarter ended
March 31,
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2008 2007 Change
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Interest expenses ($000's) 899 956 (6%)
Interest expenses per boe $2.59 $2.94 (12%)
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Depletion, Amortization and Accretion
In the quarter ended March 31, 2008 Depletion, Amortization and Accretion ("DA&A") totaled $8.9 million ($25.67 per boe) down four percent compared to $9.3 million ($28.70 per boe) for the quarter ended March 31, 2007. The per unit depletion rate declined 11 percent comparing the first quarter of 2008 to the first quarter of 2007 as ongoing drilling success and low cost reserve additions have brought down per unit DA&A rates throughout 2007 and 2008.
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Depletion, Amortization and Quarter ended
Accretion March 31,
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2008 2007 Change
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DA&A expenses ($000's) 8,929 9,343 (4%)
DA&A expenses per boe $25.67 $28.70 (11%)
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Income Taxes
The Company does not expect to pay current income tax during 2008 as there are sufficient capital cost pools and expected future capital spending to shelter taxable income.
NET LOSS
The net loss for the quarter ended March 31, 2008 was $5.4 million ($0.06 per share) compared to a net loss of $3.0 million ($0.03 per share) for the quarter ended March 31, 2007. Adjusting for the after tax amount of the unrealized loss on risk management activities of $5.6 million in the first quarter of 2008, net income was $0.2 million.
CAPITAL COSTS
For the quarter ended March 31, 2008 $11.6 million in capital costs on exploration and production activities were incurred compared to $18.2 million for the quarter ended March 31, 2007. Five net wells were drilled in the first quarter of 2008 compared to six net wells in the first quarter of 2007. Significant decreases in drilling costs have been realized in the 2008 period as operations have improved with full time staff dedicated to the drilling program and a general easing in industry cost pressures.
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Quarter ended
($000's) March 31,
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2008 2007
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Drilling and completion 7,685 11,794
Equipping and tie-ins 2,485 5,284
Land 1,341 107
Geological and geophysical 73 964
Office and other 2 12
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Total 11,586 18,161
Asset retirement obligation 353 168
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Total capital 11,949 18,329
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Drilling, completion, equip and tie-in activity represented 88 percent of the capital spent in the first quarter of 2008 as capital activity focused on developing the extensive land base. A $30 million capital budget is planned for 2008, 89 percent of which is targeted toward drilling, completion, equip and tie-in activity. It is expected that 2008 capital spending will be funded by cash flow provided by operating activities.
WORKING CAPITAL
Accounts receivable of $13.9 million at March 31, 2008 were primarily revenue receivables ($7.5 million) and amounts owing from partners ($5.1 million). Accounts payable at March 31, 2008 of $18.0 million were mainly comprised of trade payables for capital and operating costs ($10.8 million), royalties ($2.6 million), amounts owing to partners ($1.4 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($2.7 million).
Working capital excluding bank indebtedness and the unrealized loss on risk management activities was in a deficit position of $1.9 million at March 31, 2008. Borrowings under the bank line and ongoing cash flows are expected to fund the working capital deficit.
LIQUIDITY AND CAPITAL RESOURCES
The Company plans to fund its current working capital deficit, operations and capital costs with a mix of operating cash flow and debt financing through the bank operating line. An operating bank line was in place for $62.5 million at March 31, 2008, secured by producing properties. At March 31, 2008, $58.5 million was drawn on the bank line. Future capital spending is planned at amounts that can be met with expected Company cash flow.
NON-GAAP MEASUREMENTS
This MD&A contains the term "funds from operations" and "operating netback". As an indicator of the Company's performance, these terms should not be considered an alternative to, or more meaningful than "cash flow from operating activities" or "net income (loss)" as determined in accordance with Canadian generally accepted accounting principles. The Company's determination of funds from operations and operating netback may not be comparable to those reported by other companies, especially those in other industries. Management feels that funds from operations is a useful measure to help investors assess whether the Company is generating adequate cash amounts from its operations for its ongoing operations and planned capital program. Operating netback is a useful measure for comparing the Company's price realization and cost performance against industry competitors.
The reconciliation between net income and funds from operations for the periods ended March 31 is as follows:
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Quarter ended
($000's) March 31,
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2008 2007
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Cash flow provided by operating activities 8,295 8,865
Changes in non-cash working capital items related
to operating activities 974 (1,892)
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Funds from operations 9,269 6,973
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Funds from operations are also presented on a per share basis consistent with the calculation of net loss per share, whereby per share amounts are calculated using the weighted average number of shares outstanding. Funds from operations per share were $0.10 per share (basic and diluted) for the quarter ended March 31, 2008 compared to $0.07 for the quarter ended March 31, 2007 as funds from operations increased with higher volume and commodity prices and only 225,000 shares were issued in the past year of stock options exercised.
RISKS
Primary financial risks relate to volatility of commodity prices. Interest rate and currency exchange rate fluctuations also have an effect on financial results. The effect of changes in the exchange rate between US and Canadian currencies on natural gas prices is not as direct, as variations between the regional markets for natural gas are often much greater than can be explained entirely by currency variability. The Province of Alberta has announced plans for royalty changes for both conventional oil and natural gas and oil sands operations beginning in 2009. The effect of the changes to the royalty structure in Alberta may cause measurement uncertainty for certain oil and natural gas assets as oil and gas assets are valued under the new royalty system using various commodity price scenarios.
The Company entered into an interest rate swap transaction in January 2008 to fix the interest rate on $25.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at a rate of 5.21 percent including the Company's borrowing margin on its bank line. The fair value of the interest rate derivative instrument marked-to-market as at March 31, 2008 results in an unrealized loss of $184,000 as interest rates have declined since the time the interest rate swap was transacted. There were no interest rate derivatives in place in 2007.
Other risks are related to operations. These risks include, but are not limited to, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, delays or changes in plans with respect to exploration or development projects or capital costs, volatility of commodity prices, currency fluctuations, the uncertainty of reserves estimates, potential environmental liabilities, technology risks, competition for services and personnel, incorrect assessment of the value of acquisitions and failure to realize the anticipated benefits of acquisitions. The foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect operations or financial results are included in a more detailed description of risks in Berens' Annual Information Form on file with Canadian securities regulatory authorities and available on SEDAR at www.sedar.com.
Documented environmental health and safety plans are in place as well as a comprehensive emergency response plan to mitigate operating risks.
COMMODITY PRICE RISK MANAGEMENT
The Company may use financial derivative or fixed price contracts to manage its exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company applies the fair value method of accounting for derivative instruments by initially recording an asset or liability, and recognizing changes in the fair value of the derivative instrument in income.
The following is a summary of natural gas and crude oil price risk management financial derivative contracts in effect as of the date of this MD&A. All natural gas contracts are priced in Canadian dollars per gigajoule (GJ). The price per GJ can be converted to an approximate price per MCF by multiplying the per GJ price by 1.05. GJ can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95.
NATURAL GAS HEDGING
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Daily
quantity
(GJ) Term of contract Fixed price per gigajoule
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2,000 January 1 to December 31, 2008 $6.65 fixed price
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2,000 April 1 2008 to March 31, 2009 $6.72 fixed price
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2,000 April 1 to December 31, 2008 $6.65 fixed price
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2,000 April 1 to December 31, 2008 $6.80 fixed price
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2,000 April 1 to October 31, 2008 $6.80 fixed price
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2,000 April 1 to October 31, 2008 $7.45 fixed price
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CRUDE OIL HEDGING
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Daily
quantity Fixed price per barrel
(bbl) Term of contract (US WTI translated to C$)
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100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap
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100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap
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The fair value of the above natural gas derivative instruments marked to market as at March 31, 2008, results in an unrealized loss position of $7,532,000 compared to an unrealized gain position of $162,000 at December 31, 2007 as crude oil and natural gas prices have increased significantly since December 31, 2007. There was $140,000 ($0.40 per boe) of realized gains on derivative instruments for the quarter ended March 31, 2008 (2007 - $13,000). The average fixed price of the natural gas hedging transactions for the remainder of 2008 is $6.82 per GJ ($7.18 per mcf) which will provide protection to corporate cash flow if natural gas prices fall below these levels. The average floor price for the oil hedges is $85.00 per barrel.
Absent the above-noted risk management contracts, the effects of changes in commodity prices on cash flow before working capital changes are summarized in the following table.
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Cash flow
Price change
Commodity change ($ 000's)
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Natural gas ($/mcf) 1.00 $5,900
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Oil and Liquids ($/bbl) 10.00 $1,600
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RELATED PARTY TRANSACTIONS
Fees for legal services are paid to a law firm in which the corporate secretary is a partner. The legal services are rendered in the normal course of business at normal rates charged by the law firm. Legal fees for this firm paid for the quarter ended March 31, 2008 were $57,000 (2007 - $109,000).
SHARE DATA
As of the date of this MD&A the Company had 93,172,064 issued and outstanding common shares. Additionally, as at March 31, 2008 options to purchase 6,238,200 common shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
The Company has established procedures and internal control systems designed to ensure timely and accurate preparation of financial, internal management and other reports. Disclosure controls and procedures are in place designed to ensure all ongoing statutory reporting requirements are met and material information is disclosed on a timely basis. The Chief Executive Officer and the Chief Financial Officer, individually, sign certifications that the financial statements, together with the other financial information included in the regulatory filings, fairly present in all material respects the financial condition, results of operation, and cash flows as of the dates and for the periods represented.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of Berens is responsible for establishing and maintaining adequate internal controls over financial reporting. Internal controls over financial reporting are part of a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and monitored by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles ("GAAP").
The Company reported on these controls as part of its 2007 continuous disclosure requirements (please refer to the MD&A for the year ended December 31, 2007 available on SEDAR (www.SEDAR.com) and on our website www.berensenergy.com). There have been no changes to internal controls over financial reporting or management's assessment of the design of these internal controls in the period since December 31, 2007.
RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT
ACCOUNTING PRONOUNCEMENTS
The MD&A is based on the consolidated financial statements, which have been prepared in Canadian dollars in accordance with GAAP. The application of GAAP requires management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates are based on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates under different assumptions or conditions.
CHANGES IN ACCOUNTING POLICIES
Financial instruments presentation and disclosure
Effective January 1, 2008, the Company adopted the new Canadian Instutute of Chartered Accountants (CICA) recommendations relating to Financial Instruments - Disclosure (section 3862) and Financial Instruments - Presentation (section 3863). The new disclosure required by section 3862 concerning the nature and extent of the risks associated with financial instruments and how those risks are managed, is presented in note 11. Effective January 1, 2008 the company adopted CICA recommendations relating to Capital Disclolsures (section 1535). As permitted, comparative information for the disclosure required by section 3862 has not been provided.
Inventories
Effective January 1, 2008 new CICA recommendations relating to Inventories (section 3031) came into effect. The new standard provides additional guidance concerning measurement, classification and disclosure and allows the reversal of write-downs to net realizable value when there is a change in the circumstances giving rise to the impairment. The Company had adopted these recommendations for the December 31, 2007 financial statements which resulted in a re-classification of certain inventory to property, plant and equipment. At March 31, 2008 $872,000 of inventory was re-classified to property, plant and equipment.
For a discussion of Risks and Uncertainties, Critical Accounting Estimates and Recent Accounting Pronouncements please refer to the audited financial statements and the Annual Information Form for the year ended December 31, 2007 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com).
OUTLOOK
Drilling success and resulting production growth which was experienced throughout 2007 has continued into the first quarter of 2008. Net drilling success in the first quarter of 2008 was 89 percent and a disciplined approach to cost management has achieved significant reduction in our cost structure supported by moderation in the overall industry cost structure. Internally calculated finding and development costs for the first quarter of 2008 have been consistent with the costs experienced in 2007.
Capital spending for 2008 is projected at $30 million and will be funded with cash flow from operations. This capital budget was set in November 2007 using natural gas prices of $7.00 per MCF. With stronger natural gas prices to date in 2008 and continued projections of prices above $7.00, cash flows are expected to be higher which may result in an increased capital spending for the remainder of 2008. Capital spending for 2008 will be focused in Pembina where the reserve life of new wells is longest and the wells have the strongest economics. There are currently 100 inventoried drilling locations on existing lands. Drilling is expected to commence again in the middle of June 2008 at Pembina where we expect to drill on an ongoing basis until the end of the year and at Lanfine where seven wells are planned to be drilled by the middle of July.
Debt and working capital balances have improved and will continue to improve with the planned capital spending plans. Based on first quarter results on an annualized basis, debt and working capital (excluding the unrealized loss on risk management) represents 1.7 times funds from operations. With an extensive land base, a large number of drilling locations and improving natural gas prices, management anticipates that the Company will be positioned to develop our asset base more aggressively in the second half of 2008.
Berens Energy Ltd.
Balance Sheets - unaudited
As at,
-------------------------------------------------------------------------
(000's) March December
31, 2008 31, 2007
-------------------------------------------------------------------------
ASSETS (note 7)
Current
Cash and cash equivalents (note 4) $ 2 $ 1
Accounts receivable 13,876 10,315
Unrealized gain on risk management (note 11) - 162
Prepaid expenses and deposits 647 442
-------------------------------------------------------------------------
14,525 10,920
Property, plant and equipment (note 5) 169,425 166,405
-------------------------------------------------------------------------
$183,950 $177,325
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Bank loan (note 7) $ 58,500 $ 53,900
Accounts payable and accrued liabilities 18,003 16,523
Unrealized loss on risk management (note 11) 7,715 -
Taxes payable 18 14
-------------------------------------------------------------------------
84,236 70,437
Asset retirement obligations (note 6) 3,636 3,273
Future income taxes 7,856 10,199
-------------------------------------------------------------------------
95,728 83,909
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Shareholders' equity
Capital stock (note 8) 148,263 148,263
Contributed surplus (note 8) 2,414 2,195
Deficit (62,455) (57,042)
-------------------------------------------------------------------------
88,222 93,416
-------------------------------------------------------------------------
$183,950 $177,325
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited interim financial statements
Berens Energy Ltd.
Statements of Operations, Comprehensive Loss and Deficit - unaudited
For the quarter ended March 31,
-------------------------------------------------------------------------
(000's)
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
Revenue
Oil and natural gas revenue $ 18,793 $ 15,544
Royalties (4,276) (3,764)
-------------------------------------------------------------------------
14,517 11,780
Realized gain on commodity price risk
management (note 11) 140 13
-------------------------------------------------------------------------
14,657 11,793
Unrealized loss on commodity price risk
management (note 11) (7,693) (1,207)
-------------------------------------------------------------------------
6,964 10,586
-------------------------------------------------------------------------
Expenses
Production 2,880 2,643
Transportation 406 285
Depletion, amortization and accretion 8,929 9,343
General and administrative (note 10) 1,199 933
Stock-based compensation (note 8) 219 203
Interest 899 956
Unrealized loss on interest rate risk
management (note 11) 184 -
-------------------------------------------------------------------------
14,716 14,363
-------------------------------------------------------------------------
Loss before income taxes (7,752) (3,777)
Income taxes
Future expense (recovery) (2,343) (737)
Current expense 4 3
-------------------------------------------------------------------------
(2,339) (734)
-------------------------------------------------------------------------
Net loss and comprehensive loss for the period (5,413) (3,043)
Deficit, beginning of period (57,042) (29,602)
-------------------------------------------------------------------------
Deficit, end of period $(62,455) $(32,645)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Net loss per share (note 12)
Basic and diluted $ (0.06) $ (0.03)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited interim financial statements
Berens Energy Ltd.
Statements of Cash Flows - unaudited
For the quarter ended March 31,
-------------------------------------------------------------------------
(000's)
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
OPERATING ACTIVITIES
Net loss for the quarter $ (5,413) $ (3,043)
Add items not involving cash
Depletion, amortization and accretion 8,929 9,343
Unrealized risk management loss 7,877 1,207
Future income tax recovery (2,343) (737)
Stock-based compensation 219 203
-------------------------------------------------------------------------
9,269 6,973
Change in non-cash working capital items related
to operating activities (note 9) (3,590) 684
-------------------------------------------------------------------------
Cash flow provided by operating activities 5,679 7,657
-------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in bank loan 4,600 9,900
-------------------------------------------------------------------------
Cash flow provided by financing activities 4,600 9,900
-------------------------------------------------------------------------
INVESTING ACTIVITIES
Purchase of property and equipment (11,586) (18,161)
Change in non-cash working capital items related
to investing activities (note 9) 1,308 604
-------------------------------------------------------------------------
Cash flow used in investing activities (10,278) (17,557)
-------------------------------------------------------------------------
Increase in cash and cash equivalents 1 -
Cash and cash equivalents, beginning of period 1 10
-------------------------------------------------------------------------
Cash and cash equivalents, end of period $ 2 $ 10
-------------------------------------------------------------------------
-------------------------------------------------------------------------
See accompanying notes to the unaudited interim financial statements
BERENS ENERGY LTD.
Notes to Financial Statements - unaudited
Quarters ended March 31, 2008 and 2007
1. NATURE OF OPERATIONS
Berens Energy Ltd. (the "Company") is a full cycle oil and natural gas
exploration and production company with activities encompassing land
acquisition, geological and geophysical assessment, drilling and
completion, and production. The primary areas of operation are in eastern
and west central Alberta.
2. SEASONALITY
Significant capital spending activity occurs in the winter months in the
western Canadian oil and natural gas business as many areas are only
accessible or best accessed in the winter months when the ground is
frozen. Limited capital spending activity tends to occur in the second
calendar quarter as the industry experiences "spring break-up" when there
is significant water on the ground due to melting snow and roads
capacities are limited as winter frost melts and the roads are wet and
unable to support heavy loads. Normal oil and gas operations tend to
return in the June time frame each year.
3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The financial statements have been prepared by management in accordance
with Canadian generally accepted accounting principles ("GAAP"). The
nature of the business and timely preparation of financial statements
requires that management make estimates and assumptions, and use judgment
regarding assets, liabilities, revenues and expenses. Such estimates
primarily relate to unsettled transactions and events as of the date of
the financial statements. Accordingly, actual results may differ from
estimated amounts. In the opinion of management, these financial
statements have been properly prepared within reasonable limits of
materiality and within the framework of the significant accounting
policies summarized below.
Certain disclosures, which are normally required to be included in notes
to the annual financial statements, are condensed or omitted for interim
reporting purposes. Accordingly, these interim financial statements
should be read in conjunction with the audited annual financial
statements for the year ended December 31, 2007. Certain prior period
amounts have been reclassified to conform to current disclosure.
The financial statements have been prepared following the same accounting
policies and methods of computation as the Annual Financial Statements
for the year ended December 31, 2007.
a) CHANGES IN ACCOUNTING POLICIES
Financial instruments presentation and disclosure
Effective January 1, 2008, the Company adopted the new Canadian Instutute
of Chartered Accountants (CICA) recommendations relating to Financial
Instruments - Disclosure (section 3862) and Financial Instruments -
Presentation (section 3863). The new disclosure required by section 3862
concerning the nature and extent of the risks associated with financial
instruments and how those risks are managed, is presented in note 11.
Effective January 1, 2008 the company adopted CICA recommendations
relating to Capital Disclolsures (section 1535). As permitted,
comparative information for the disclosure required by section 3862 has
not been provided.
Inventories
Effective January 1, 2008 new CICA recommendations relating to
Inventories (section 3031) came into effect. The new standard provides
additional guidance concerning measurement, classification and disclosure
and allows the reversal of write-downs to net realizable value when there
is a change in the circumstances giving rise to the impairment. The
Company had adopted these recommendations for the December 31, 2007
financial statements which resulted in a re-classification of certain
inventory to property, plant and equipment. At March 31, 2008 $872,000 of
inventory was re-classified to property, plant and equipment.
4. CASH AND CASH EQUIVALENTS
Cash and cash equivalents are in the form of cash bank balances or
certificates of deposit from Canadian financial institutions with terms
of less than 90 days. The effective interest rate on the deposits at
March 31, 2008 was 2.3 percent (2007 - 2.3 percent).
5. PROPERTY, PLANT AND EQUIPMENT
March 31, 2008 December 31, 2007
Accumulated Accumulated
depletion and depletion and
($000's) Cost depreciation Cost depreciation
-------------------------------------------------------------------------
Petroleum and
natural gas
properties 286,004 116,952 274,067 108,045
Office and
computer equipment 736 363 734 351
-------------------------------------------------------------------------
286,740 117,315 274,801 108,396
-------------------------------------------------------------------------
Net book value 169,425 166,405
-------------------------------------------------------------------------
At March 31, 2008, costs of $22,048,000 (December 31, 2007 - $21,159,000)
related to undeveloped land have been excluded from the depletion and
depreciation calculation. At March 31, 2008 estimated future development
costs of $15,511,000 have been included in the depletion and depreciation
calculation. A ceiling test was completed at March 31, 2008 resulting in
no impairment.
6. ASSET RETIREMENT OBLIGATIONS
The total future asset retirement obligations were estimated based on the
net ownership interest in all wells and facilities, estimated costs to
reclaim and abandon the wells and facilities and the estimated timing of
the costs to be incurred in future periods. The estimated net present
value of the total asset retirement obligations is $3,636,000 as at
March 31, 2008 (2007 - $2,888,000) based on a total future liability of
$8,828,000 (2007 - $8,019,000). These payments are expected to be made
over the next 5 to 15 years. An inflation rate of 2 percent and a credit
adjusted risk free rate of 10 percent were used to calculate the present
value of the asset retirement obligations.
The following table reconciles the asset retirement obligations:
($000's) 2008
-------------------------------------------------------------------------
Obligation, beginning of period 3,273
Increase in obligation during the period 354
Accretion expense 9
-------------------------------------------------------------------------
Obligation, end of period 3,636
-------------------------------------------------------------------------
7. BANK OPERATING LINE
An agreement with a Canadian bank is in place for an operating bank line
totaling $62.5 million at March 31, 2008. Collateral for the facility
consists of a general assignment of book debts and a $35.0 million
debenture with a floating charge over all assets of the Company and a
$75.0 million supplemental debenture with a floating charge over all
assets of the Company. The bank line is a demand line and carries an
interest rate of the Bank's prime rate adjusted for a factor based on the
most recent quarterly debt to cash flow calculation. The average rate
paid for the quarter ended March 31, 2008 was 6.4 percent
(2007 - 7.1 percent).
8. CAPITAL STOCK
(a) Authorized Capital
The authorized capital consists of an unlimited number of preferred
shares issuable in series and an unlimited number of common shares
without nominal or par value.
(b) Common shares issued
-------------------------------------------------------------------------
Consideration
Number ($000's)
-------------------------------------------------------------------------
Balance December 31, 2006 92,947,064 148,038
Shares issued on exercise of stock options 225,000 225
-------------------------------------------------------------------------
Balance December 31, 2007 and March 31, 2008 93,172,064 148,263
-------------------------------------------------------------------------
(c) Stock Option Plan
A stock option plan is in place under which 7,500,000 common shares have
been reserved for options to be granted to directors, officers, employees
and consultants with terms established by the Board of Directors.
Options granted under the plan generally have a five year term to expiry
and vest equally over a three year period commencing on the first
anniversary date of the grant. The exercise price of each option equals
the closing market price of the Company's common shares on the day prior
to the date of the grant.
The following table sets forth a reconciliation of the plan activity
through March 31, 2008:
2008 2007
Weighted Weighted
average average
Number of exercise price Number of exercise price
Options ($ per share) Options ($ per share)
-------------------------------------------------------------------------
Outstanding,
beginning of
period 6,238,200 1.42 4,416,200 1.68
Granted - - 1,057,000 0.99
Forfeited - - (205,000) 1.19
-------------------------------------------------------------------------
Outstanding,
end of period 6,238,200 1.42 5,268,200 1.53
-------------------------------------------------------------------------
Exercisable 3,631,851 1.51 2,696,360 1.39
-------------------------------------------------------------------------
The following table sets forth additional information relating to the
stock options outstanding at March 31, 2008:
Options Outstanding Exercisable Options
-------------------------------------------------------------------------
Weighted Weighted
average average
exercise Weighted exercise Weighted
price average price average
Exercise price Number of ($ per years to Number of ($ per years to
range Options share) expiry Options share) expiry
-------------------------------------------------------------------------
$0.50 to $1.39 4,053,500 1.00 2.69 2,101,659 1.07 1.35
$1.40 to $2.29 1,127,200 1.54 1.80 866,867 1.51 1.33
$2.30 to $3.19 917,500 2.83 2.73 569,992 2.86 2.71
$3.20 to $4.09 140,000 3.24 2.82 93,333 3.24 2.82
6,238,200 1.42 2.54 3,631,851 1.51 1.60
-------------------------------------------------------------------------
The fair value method for measuring option awards based on the Black
Scholes valuation model is used. Estimated future forfeiture assumptions
are not used in calculations as forfeitures are recognized as they occur.
The weighted average option price for options outstanding at March 31,
2008 is $0.567 per option. For the quarter ended March 31 2008, $219,000
(2007 - $203,000) was recorded for options issued and outstanding with a
corresponding increase recorded to contributed surplus. Subsequent to the
end of the first quarter of 2008, 959,000 stock options were issued with
an exercise price of $0.87 per share.
(d) Contributed Surplus
The following table sets forth the continuity of contributed surplus for
the year ended March 31, 2008:
($000's)
-------------------------------------------------------------------------
December 31, 2007 2,195
2008 Stock based compensation expense 219
-------------------------------------------------------------------------
March 31, 2008 2,414
-------------------------------------------------------------------------
9. SUPPLEMENTAL CASH FLOW INFORMATION
Changes in Non-cash Working Capital
For the quarters ended March 31,
($000's) 2008 2007
-------------------------------------------------------------------------
Accounts receivable (3,561) (6,085)
Prepaid expenses and deposits (205) 86
Accounts payable and accrued liabilities 1,480 7,284
Taxes payable 4 3
-------------------------------------------------------------------------
(2,282) 1,288
Change in non-cash working capital related
to investing activities 1,308 604
-------------------------------------------------------------------------
Change in non-cash working capital related
to operating activities (3,590) 684
-------------------------------------------------------------------------
Cash interest and taxes paid
For the quarters ended March 31,
($000's) 2008 2007
-------------------------------------------------------------------------
Cash income and other taxes paid - -
Cash interest paid 899 956
-------------------------------------------------------------------------
10. RELATED PARTY TRANSACTIONS
Fees for legal services are paid to a law firm in which the corporate
secretary is a partner. The legal services are rendered in the normal
course of business at normal rates charged by the law firm. Legal fees
for this firm paid for the quarter ended March 31, 2008 were $57,000
(2007 - $109,000).
11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Financial assets and liabilities recognized on the balance sheets consist
of cash and cash equivalents, accounts receivable, deposits, accounts
payable, accrued liabilities, bank loan and financial derivatives used to
manage interest rate, natural gas and oil price risk.
Fair value of financial assets and liabilities
Cash, deposits, investments, cash equivalents, financial derivatives and
bank indebtedness are designated as "held-for-trading". Accounts
receivable are designated as "loans and receivables" and accounts payable
are designated as "other liabilities". The fair value of these financial
instruments approximates their carrying amounts due to their short terms
to maturity except for derivatives used for interest rate and commodity
price risk management which values are outlined below.
(a) Credit Risk
Accounts receivable are with customers, sales agents and joint venture
partners in the petroleum and natural gas business and are subject to the
usual credit risks. The Company mitigates this risk by entering into
transactions with long-standing, reputable counterparties and partners.
If significant amounts of capital are to be spent on behalf of a joint
venture partner the partner is "cash called" in advance of the capital
spending taking place. The maximum credit exposure with accounts
receivable is the carrying value. At March 31, 2008, the largest single
credit exposure was approximately $6.8 million from the Company's sales
agent which balance is settled monthly. At March 31, 2008, seven percent
of accounts receivable were non-current as defined by accounts over
90 days outstanding. No allowance for doubtful accounts receivable has
been recorded nor are any deemed to be impaired.
(b) Interest Rate Risk
The Company is exposed to fluctuations in interest rates on its bank debt
which charges interest at variable market rates. The Company entered into
an interest rate swap transaction in January 2008 to fix the interest
rate on $25.0 million of its variable rate demand bank line. The
transaction fixes the interest rate for a two year period at a rate of
5.21 percent including the Company's borrowing margin on its bank line.
Fair values for interest rate derivatives are provided by the financial
intermediary with whom the transactions were completed and tested by the
Company for reasonableness based on comparing current market prices and
the fixed prices of the contracts. The fair value of the interest rate
derivative instrument marked-to-market as at March 31, 2008 results in an
unrealized loss of $184,000. There were no interest rate derivatives in
place in 2007. The net income effect of a one percent change in
short-term interest rates on the remaining amount of bank debt is
approximately $225,000.
(c) Foreign Exchange Risk
The Company is exposed to the risk of changes in the Canadian/US dollar
exchange rates on sales of commodities that are denominated in U.S.
dollars or directly influenced by U.S. dollar benchmark prices. No
specific currency hedging has been undertaken, however, all commodity
price risk management activities hedge revenue into Canadian dollars. The
net income effect of a $0.01 change in the exchange rate between the US
and Canadian dollars is approximately $575,000.
(d) Commodity Price Risk Management
The Company is exposed to the risk of changes in market prices for
natural gas, crude oil and natural gas liquids. The Company may hedge
this risk by entering into derivatives based fixed price contracts or
price collars or may enter into fixed price physical delivery contracts.
The following is a summary of natural gas price risk management
derivative contracts in effect as of March 31, 2008. All natural gas
contracts are priced in Canadian dollars per gigajoule ("GJ"). The price
per GJ can be converted to an approximate price per million cubic feet
("MCF") by multiplying the per GJ price by 1.05. GJ volume can be
converted to an approximate MCF volume by multiplying the GJ volume by
0.95.
Natural Gas Risk Management Contracts
-------------------------------------------------------------------------
Daily Term of Contract Fixed price per gigajoule
quantity (Cdn$/GJ)
(GJ/day)
-------------------------------------------------------------------------
2,000 April 1 to March 31, 2009 $6.72 fixed price
-------------------------------------------------------------------------
2,000 April 1 to December 31, 2008 $6.65 fixed price
-------------------------------------------------------------------------
2,000 January 1 to December 31, 2008 $6.65 fixed price
-------------------------------------------------------------------------
2,000 April 1 to December 31, 2008 $6.80 fixed price
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2008 $6.80 fixed price
-------------------------------------------------------------------------
2,000 April 1 to October 31, 2008 $7.45 fixed price
-------------------------------------------------------------------------
Crude Oil Risk Management Contracts
-------------------------------------------------------------------------
Daily Term of Contract Fixed price per barrel
quantity (WTI in Cdn$)
(Barrels/d)
-------------------------------------------------------------------------
100 January 1 to December 31, 2008 $85.00 floor; $93.30 cap
-------------------------------------------------------------------------
100 January 1 to December 31, 2008 $85.00 floor; $98.10 cap
-------------------------------------------------------------------------
Fair values for commodity price derivatives are provided by the financial
intermediary with whom the transactions were completed and tested by the
Company for reasonableness based on comparing current market prices and
the fixed prices of the contracts. The fair value of the above natural
gas and crude oil derivative instruments marked-to-market as at March 31,
2008 results in an unrealized loss of $7,532,000 (December 31, 2007 -
gain of $162,000). Total realized gains from risk management activities
in the first quarter of 2008 were $140,000 (2007 - $13,000). Commodity
price and interest rate derivatives are transacted with large, credit
worthy counterparties and governed by credit agreements between the
Company and its counterparties.
Absent the above-noted risk management contracts, the effects of changes
in commodity prices on net income summarized in the following table.
-------------------------------------------------------------------------
Commodity Price change Cash flow change
($ 000's)
-------------------------------------------------------------------------
Natural gas ($/mcf) 1.00 $4,200
-------------------------------------------------------------------------
Oil and Liquids ($/bbl) 10.00 $1,100
-------------------------------------------------------------------------
(e) Liquidity Risk and Capital Requirements
The Company is exposed to liquidity risk, which is the risk that the
Company may be unable to generate or obtain sufficient cash to meet its
commitments as they become due. This risk is mitigated through the
management of cash and debt and the Company may adjust capital spending,
issue new shares or draw or repay its operating bank line. The Company's
primary capital management objective is to maintain a strong balance
sheet to provide the financial flexibility to respond to cash flow
volatility or an investment opportunity. The Company maintains
appropriate unused capacity in its operating bank line to meet short term
fluctuations from forecasted results. The Company has no externally
imposed capital requirements.
Forecasted cash flows and operating and capital outlays are updated
frequently to ensure necessary liquidity remains available. The Company
may hedge a portion of its future production and/or its interest rate
exposure to protect cash flows. All of the Company's financial
obligations are either demand or are due within one year. The Company is
targeting to reduce its debt and working capital to funds from operations
ratio to a measure of 1.5:1 on a current quarter annualized basis
(excluding unrealized hedging gains and losses from working capital),
down from historical ratios of over 2:1. For the quarter ended March 31,
2008 this ratio was 1.7:1.
-------------------------------------------------------------------------
Target
At March 31 ($000's) Measure 2008 2007
-------------------------------------------------------------------------
Components of Ratio
Current assets 14,525 27,023
Current liabilities (84,236) (94,491)
-------------------------------------------------------------------------
(69,711) (67,468)
Unrealized risk loss 7,715 572
-------------------------------------------------------------------------
Debt and working capital (61,996) (66,896)
-------------------------------------------------------------------------
Funds from operations - three months
ended March 31 annualized(1) 37,076 27,892
-------------------------------------------------------------------------
Ratio 1.5:1 1.7:1 2.4:1
-------------------------------------------------------------------------
(1) Funds from operations is a non-GAAP measure defined as: operating
cash flow adjusted for changes in non-cash working capital related to
operating activities, all annualized.
12. PER SHARE INFORMATION
The weighted average number of common shares outstanding for the quarter
ended March 31, 2008 of 93,172,064 was used to calculate basic and
diluted income (loss) per share (2007 - 93,067,132). All of the
outstanding options have been excluded from the calculation of diluted
per share information as they were anti-dilutive. The total number of
shares which are potentially dilutive in future periods as of March 31,
2008 was 6,238,200.
Caution Regarding Forward Looking Information
This press release contains forward looking information within the
meaning of applicable securities laws. Forward looking statements may
include estimates, plans, expectations, forecasts, guidance or other
statements that are not statements of fact. Forward looking information
in this Press Release includes, but is not limited to, statements with
respect to capital expenditures and related allocations, production
volumes, production mix and commodity prices.
Forward-looking statements and information are based on current beliefs
as well as assumptions made by and information currently available to
Berens concerning anticipated financial performance, business prospects,
strategies and regulatory developments. Although management considers
these assumptions to be reasonable based on information currently
available to it, they may prove to be incorrect.
By their very nature, forward-looking statements involve inherent risks
and uncertainties, both general and specific, and risks that predictions,
forecasts, projections and other forward-looking statements will not be
achieved. We caution readers not to place undue reliance on these
statements as a number of important factors could cause the actual
results to differ materially from the beliefs, plans, objectives,
expectations and anticipations, estimates and intentions expressed in
such forward-looking statements. These factors include, but are not
limited to: crude oil and natural gas price volatility, exchange rate and
interest rate fluctuations, availability of services and supplies, market
competition, uncertainties in the estimates of reserves, the timing of
development expenditures, production levels and the timing of achieving
such levels, the Company's ability to replace and increase oil and gas
reserves, the sources and adequacy of funding for capital investments,
future growth prospects and current and expected financial requirements
of the Company, the cost of future abandonment and site restoration, the
Company's ability to enter into or renew leases, the Company's ability to
secure adequate product transportation, changes in environmental and
other regulations and general economic conditions.
The forward-looking statements contained in this press release are made
as of the date of this press release, and Berens does not undertake any
obligation to up-date publicly or to revise any of the included forward-
looking statements, whether as a result of new information, future events
or otherwise. This cautionary statement expressly qualifies the forward-
looking statements contained in this press release.
ContactsDell P. Chapman
V.P. Finance & CFO
Ph: (403) 303-3267 Daniel F. Botterill
President & Chief Executive Officer
Ph: (403) 303-3262
535.02 (5.57%)