Berens Energy Ltd. Releases Financial Results for the Third Quarter and Nine Months Ended September 30, 2009
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CALGARY, ALBERTA--(Marketwire - Nov. 11, 2009) - Berens Energy Ltd. (TSX: BEN)
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($ Cdn thousands, Three months ended Nine months ended
except as noted) September 30, September 30,
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% %
2009 2008 Change 2009 2008 Change
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Sales volume
Natural gas (mcf/day) 18,450 19,592 (6%) 20,101 19,458 3%
Oil and ngls (bbl/day) 875 845 4% 874 778 12%
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boe/day (6 to 1) 3,950 4,110 (4%) 4,224 4,021 5%
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Revenue net of
royalties 8,315 17,368 (52%) 28,218 52,623 (46%)
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Net income (loss) (3,559) 8,167 (10,427) 1,142
Per share (basic and
diluted) $(0.04) $0.09 $(0.11) $0.01
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Funds from
operations(1) 4,502 8,943 (50%) 14,017 30,782 (55%)
Per share (basic and
diluted)(1) $ 0.05 $0.10 $0.15 $0.33
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Capital costs
Exploration and
development 5,808 12,325 (53%) 17,538 24,064 (27%)
Land and seismic 895 1,606 (44%) 2,494 4,035 (38%)
Other - 7 - - 14 -
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Total 6,703 13,938 (52%) 20,032 28,113 (29%)
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Net wells completed (#) 3 8 7 13
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Net working capital
deficit
excluding unrealized
hedging losses(2) (63,168) (56,819) 11% (63,168) (56,819) 11%
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Net working capital
deficit - including
unrealized hedging
losses (64,901) (57,040) 12% (64,091) (57,040) 12%
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Shares outstanding
End of period (000's) 93,547 93,547 - 93,547 93,547 -
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(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.
(2) Non-GAAP measure - adjusts working capital for unrealized hedging gains
and losses.
Third Quarter 2009 Operating Highlights
- Production - Q3 2009 production averaged 3,950 boe/d, down 4% compared to Q3 2008. Production for the first nine months of 2009 averaged 4,224 boe/d, up 5% compared to the first nine months of 2008. Fourth quarter production is expected to average 3,800 boe/d. A return to production growth is expected for Q1 2010 as commodity prices have strengthened and capital spending is expected to be higher in 2010 compared to 2009.
- Funds from Operations - Funds from operations for Q3 2009 were $4.5 million ($0.05 per share), down 50% compared to Q3 2008. For the first nine months of 2009 funds from operations were $14.0 million ($0.15 per share), down 55% compared to the first nine months of 2008. Weak natural gas and oil prices have more than offset production gains and cost improvements.
- Capital Spending - Four (2.6 net) wells were drilled in Q3 2009 resulting in three (2.4 net) successful natural gas wells. Total spending in the quarter was $6.7 million. Total planned capital spending for 2009 is $26 million before drilling credits which are expected to be $2.7 million. The operating bank line is $66 million until January 1, 2010 which will provide adequate financial flexibility to execute the planned capital spending.
- Costs - Focus on cost control continues to deliver finding & development costs based on internal measurement that are consistent with our strong 2008 results. Significant reductions in operating and G&A costs have also been achieved, improving our overall cash flows in 2009.
- Notikewin Potential - Liquids rich natural gas drilling, ongoing land acquisitions and farm-ins continue to add opportunities in the Notikewin formation which has delivered low finding and development costs over the past three years. This play will continue to be an emphasis for Berens in its 2010 capital spending plans, especially if natural gas price strength continues.
- Cardium Resource Play - Berens' first Cardium oil horizontal well completed with multi-stage frac technology tested 270 boe/d of light oil from a 600 metre horizontal leg. The test results of this well were very encouraging and confirmed that Cardium light oil potential exists on Berens' extensive land position to the west of Canada's largest Cardium oil field. A second well has been drilled and is currently being completed and tested at the time of writing. Berens has 68 sections (38 net) of Cardium rights and based on the early drilling success, estimates an inventory of approximately 170 (100 net) Cardium light oil locations on existing acreage in Pembina.
Message to the shareholders
When natural gas prices began to weaken in early 2009 we viewed the event as a window of opportunity and increased our focus on opportunities to build for the future. To capture these opportunities we established a five pronged strategy:
1. Build our drilling inventory by looking aggressively for farm-in opportunities where industry participants may be capital constrained and have expiring lands.
2. Drill only those wells that were economic and would meet our farm-in commitments to earn lands.
3. Continue to participate at crown land sales where we saw our liquids rich natural gas play evident, with an emphasis on expanding the play beyond our existing acreage.
4. Prove up our emerging Cardium oil play over which we had extensive land holdings in Pembina and;
5. Position ourselves to accelerate activity when commodity prices improved.
These strategies proved to be successful as evidenced by the results on:
Cardium Light Oil Play:
- This exciting new play was proven following the end of the third quarter with a production test of 270 boe/d from our first Cardium oil horizontal well.
- A second well is currently being tested and plans to drill four more wells by the end of Q1 2010 are in place.
- We have 68 sections (38 net) of Cardium rights in Pembina with a potential inventory of 170 locations (100 net) that offer significant oil growth potential and value to shareholders.
Inventory Building:
- We have continued to build our drilling inventory of liquids rich natural gas wells by adding 13.5 sections (12.0 net) in Pembina so far this year. This has been done through crown land sales and creative deals with industry partners.
- Lands have been acquired that push the boundaries of our Pembina play.
- Much of the land added will be prospective for not only liquids rich natural gas, but also our Cardium oil resource play.
Natural gas prices have recovered from the summer lows. This price recovery, combined with strong oil prices and recent hedging of natural gas prices will enable us to capitalize on our improved inventory of opportunities and step up our capital spending program as we exit this year and head into 2010. With increased spending we expect to return to significant production and reserve growth in 2010. We are finalizing our 2010 spending plans and are excited with the potential that our plans offer for growth in value for our shareholders.
Sincerely,
Daniel F. Botterill - President & Chief Executive Officer
Berens Energy Ltd.
Third Quarter 2009
Management's Discussion and Analysis ("MD&A")
November 11, 2009
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 Pembina, Deep Basin and Eastern 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 September 30, 2009 unaudited financial statements and its December 31, 2008 audited financial statements and notes thereto. This MD&A was prepared using information that is current as of November 10, 2009 unless otherwise noted.
STRATEGY AND OBJECTIVES
The Company has established key performance metrics for 2009 that are evaluated and reviewed quarterly within the context of an annual capital program that is funded by projected cash flows supplemented by drilling credits and an increase in the amount drawn on the bank operating line. The 2009 capital budget of $26 million is based on an assumed Cdn$4.10 per mcf price for natural gas at AECO and Edmonton reference light oil at Cdn$70.00. The current strategy in the low natural gas price environment is focused on adding land and drilling inventory through farm-ins and land deals that are earned by drilling wells that also benefit from the drilling credit program recently announced by the Province of Alberta. Spending is planned for the fourth quarter of 2009 to further test the new Cardium light oil resource play on the Company's Pembina lands. Key performance metrics include production volume growth, finding and development costs, reserve additions, operating and corporate netbacks and return on investment.
Volume growth is an important equity market measurement that is reported frequently and measures the ability of the capital spending program to add near term cash flow. The Company expects production volume to average 4,100 boe per day in 2009 under the $26 million capital plan, down three percent compared to 2008 average production of 4,222 boe per day.
Longer term value is achieved by adding oil and natural gas reserves at low cost. The Company expects to replace 1.5 times 2009 production with new reserves at finding and development costs below $14.00 per boe. Operating and corporate cash netbacks are expected to be $21.00 and $15.00 per boe respectively assuming a $4.10 per mcf price for natural gas and $70.00 per barrel for oil. Resulting recycle ratios based on the above factors are approximately 1.5 times on an operating netback basis and 1.1 times based on the corporate netback. These recycle ratios improve significantly with stronger commodity prices.
ECONOMIC UNCERTAINTY
Recent economic events have created volatility and an uncertain environment for stock and credit markets and commodity prices in the foreseeable future. Berens' bank line of credit is $66 million at September 30, 2009 and will remain at $66 million until January 1, 2010 at which time it reduces by $1.0 million per month until a February 2010 review date. The December 31, 2009 reserves evaluation will then be taken into consideration to re-establish a new, go forward bank line amount. Further, the Company has conducted its capital spending program within cash flow since the second quarter of 2006 in periods of both high and low commodity prices. During this period Berens has shown consistent growth in both reserves and production. Excluding unrealized hedging losses, debt and working capital deficiency was $63.2 million at September 30, 2009. Capital spending for the balance of 2009 is forecasted to be approximately $9 million net of drilling credits which results in an expected debt and working capital deficiency balance of approximately $63 million at December 31, 2009.
Berens has a focused asset base with high working interest and operates approximately 85% of its planned capital spending. This high working interest and operatorship allows Berens to control the pace and focus of its capital spending to maintain financial flexibility in various commodity price and economic environments.
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 and exchange rate volatility which may result in actual prices differing from our assumed $4.10/mcf natural gas and $70.00 Edmonton Reference oil price resulting in different cash netbacks, recycle ratios and cash flows. Availability, the timing of and costs of services and supplies may fluctuate causing finding and development costs to vary from those forecasted and cause the production levels and the timing of achieving forecasted production levels to be different than those assumed. The success that the Company has with its drilling program and its ability to increase oil and gas reserves may be different than the success assumed in establishing its finding and development cost and production growth assumptions. Other risks include market competition, uncertainties in the estimates of reserves, the sources and adequacy of funding for capital investments, future growth prospects and current and expected financial requirements of the Company, interest rate fluctuations, 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.
Additional information on the Company can be found on the SEDAR website at www.sedar.com.
QUARTERLY INFORMATION
2009 2008 2007
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($000's except
as noted) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4
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Sales volumes:
Natural gas
(mcf/day) 18,450 20,152 21,735 23,632 19,592 19,677 19,104 19,018
Oil and
natural
gas liquids
(bbl/day) 875 821 927 882 845 859 628 626
Barrels
of oil
equivalent
(boe/day) 3,950 4,180 4,550 4,821 4,110 4,139 3,812 3,796
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Financial:
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Net
revenue 8,315 9,038 10,866 14,516 17,368 20,738 14,517 13,214
Net income
(loss) (3,559) (3,782) (3,086) (698) 8,167 (1,612) (5,413) (680)
per share
- basic
($/share) (0.04) (0.04) (0.03) (0.01) 0.09 (0.02) (0.06) (0.01)
per share
- diluted
($/share) (0.04) (0.04) (0.03) (0.01) 0.09 (0.02) (0.06) (0.01)
Capital
costs 6,703 1,977 11,351 11,979 13,997 2,715 11,586 6,718
Shares
outstanding
(000's) 93,547 93,547 93,547 93,547 93,547 93,547 93,172 93,172
Bank debt 62,000 60,500 61,000 54,600 48,500 53,000 58,500 53,900
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Working
capital
(deficit) (64,901)(61,906)(64,054)(59,386)(57,040)(64,943)(69,711)(59,516)
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Working
capital
(deficit)
excluding
unrealized
hedging
gains and
losses(1) (63,168)(60,966)(62,956)(58,751)(56,819)(51,766)(61,996)(59,678)
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Per unit
information:
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Natural gas
price
($/mcf) 3.21 3.82 5.57 7.10 8.77 10.55 8.12 6.52
Oil and
liquids price
($/barrel) 55.23 51.86 40.64 47.48 100.31 103.76 81.76 71.66
Oil equivalent
price
($/boe) 27.21 28.61 34.90 43.49 62.41 71.70 54.16 44.48
Operating
netback
($/boe) 15.33 15.15 12.68 24.63 36.19 46.31 32.36 26.85
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Net wells
completed: (#)
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Natural gas 3 - 3 2 8 - 5 3
Oil - - - - - - - -
Dry - - 1 1 2 - - -
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Total 3 - 4 3 10 - 5 3
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(1) Non-GAAP measure
Ongoing drilling has delivered the overall production increases for 2007 and to the fourth quarter of 2008. The significant increase in natural gas production in Q4 2008 was due to significant flush production from an active, successful drilling program in the second and third quarters of 2008. The Company's first high rate horizontal well also came on stream in November 2008 adding to the Q4 2008 volume. The declines in Q1 2009 compared to the fourth quarter of 2008 were due to the restriction of 250 boe per day in the Lanfine area to preserve asset value under new Alberta royalty regulations which took affect on January 1, 2009. Lower drilling activity in the first two quarters of 2009 due to lower commodity prices and reduced cash flows combined with natural declines have also contributed to lower production levels in Q2 and Q3 2009 compared to Q4 2008. The net income amount in Q3 2008 was primarily due to a large positive swing in the unrealized gain position on commodity price risk management derivatives in place in Q3 2008.
RESULTS OF OPERATIONS Production Volume
Volume averaged 3,950 boe/d for the quarter ended September 30, 2009, down four percent compared to 4,110 boe/d for the quarter ended September 30, 2008 and down six percent from the second quarter of 2009. Natural gas represented 78 percent of production in the third quarter of 2009 with the remaining production being 21 percent light oil and natural gas liquids and one percent conventional heavy oil. No wells were drilled in the second quarter of 2009 due to spring break-up and third quarter drilling did not commence until July 2009 due to weak natural gas prices and a desire to keep capital spending within cash flow. Four wells (2.6 net) were drilled during the third quarter of 2009 with three (2.4 net) of these wells brought on stream late in the quarter resulting in the additional volume from the new wells not contributing significantly in the quarter. Natural declines in the quarter more than offset the new production.
For the nine months ended September 30, 2009 volume averaged 4,224 boe/d, up five percent over the nine months ended September 30, 2008. The increased volume is due to ongoing drilling success, primarily in Pembina. In particular, the first quarter 2009 production volume was strong due to initial production from a large number of wells brought on stream in the final quarter of 2008 and early 2009 including two high volume horizontal natural gas wells in Pembina.
Production Revenue
Natural gas prices averaged $3.21 per mcf for the quarter ended September 30, 2009, down 63 percent compared to $8.77 per mcf in the quarter ended September 30, 2008. Oil and liquids prices averaged $65.89 and $53.47 per barrel respectively for the quarter ended September 30, 2009 for a blended price of $55.23 per barrel, down 45 percent from the quarter ended September 30, 2008 blended oil and liquids price of $100.31 per barrel. On a per boe basis, prices averaged $27.21 in the quarter ended September 30, 2009, down 56 percent compared to $62.41 per boe in the quarter ended September 30, 2008. Revenue before results from hedging was down 58 percent in the quarter ended September 30, 2009 compared to the quarter ended September 30, 2008 primarily due to the decline in both oil and natural gas prices combined with a small volume decline. An additional $1.11 per boe was realized from hedging gains during the quarter ended September 30, 2009 for total revenue of $28.32 per boe. In the quarter ended September 30, 2008 realized hedging losses amounted to $6.91 per boe.
For the nine months ended September 30, 2009, natural gas prices averaged $4.26 per mcf down 53 percent compared to $9.15 per mcf in the nine months ended September 30, 2008. Combined oil and liquids prices averaged $49.07 per barrel for the nine months ended September 30, 2009, down 49 percent from the nine months ended September 30, 2008 blended oil and liquids price of $96.60 per barrel. On a boe basis prices averaged $30.40 per boe in the nine months ended September 30, 2009, down 52 percent compared to $62.99 per boe in the nine months ended September 30, 2008. Oil and natural gas revenue was down 49 percent for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008 as volume increases were more than offset by weaker prices. Realized hedging gains during the nine months ended September 30, 2009 were $0.83 per boe compared to realized hedging losses of $4.77 per boe in the nine months ended September 30, 2008.
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Volumes and prices Three months ended Nine months ended
September 30, September 30,
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2009 2008 Change 2009 2008 Change
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Production revenue ($000's) 9,896 23,645 (58%) 35,123 69,446 (49%)
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Production volume
Natural gas (mcf/d) 18,450 19,592 (6%) 20,101 19,458 3%
Oil and liquids (bbl/d) 875 845 4% 874 778 12%
BOE (bbl/d) 3,950 4,110 (4%) 4,224 4,021 5%
Prices
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Natural gas ($/mcf) 3.21 8.77 (63%) 4.26 9.15 (53%)
Oil and liquids ($/bbl) 55.23 100.31 (45%) 49.07 96.60 (49%)
BOE ($/boe) 27.21 62.41 (56%) 30.40 62.99 (52%)
BOE ($/boe including hedging) 28.32 57.88 (51%) 31.23 58.22 (46%)
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Royalties
Royalties averaged 16 percent of revenue for the quarter ended September 30, 2009 compared to 27 percent for the quarter ended September 30, 2008. For the nine months ended September 30, 2009 royalties averaged 20 percent compared to 24 percent for the nine months ended September 30, 2008. Low natural gas prices have resulted in lower percent royalty rates in 2009 compared to 2008. Approximately 11 percent of production in the quarter ended September 30, 2009 came from new wells brought on stream after April 1, 2009 which qualify for a five percent royalty rate further lowering royalties by approximately 1.5 percent in the 2009 period.
Royalty expense of $1.6 million was recorded in the quarter ended September 30, 2009, down 75 percent compared to the quarter ended September 30, 2008 due to lower revenue and lower percent royalty rates. For the nine months ended September 30, 2009 royalty expense was $6.9 million, down 59 percent compared to the nine months ended September 30, 2008 again, due to lower revenue and lower percent rates.
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Royalties Three months ended Nine months ended
September 30, September 30,
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2009 2008 Change 2009 2008 Change
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Royalty expense
($000's) 1,581 6,277 (75%) 6,905 16,823 (59%)
Royalty cost per boe $ 4.35 $ 16.56 (74%) $ 5.99 $ 15.26 (61%)
Royalty cost as a
percent of revenue 16% 27% (38%) 20% 24% (17%)
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Production Expenses
Production expenses were $6.75 per boe in the quarter ended September 30, 2009, down 23 percent compared to $8.76 per boe in the quarter ended September 30, 2008. A credit from a third party processing entity for retroactive adjustment was received in the third quarter of 2009, reducing operating costs by $0.23 per boe. In addition, continued efforts to control field operation costs have been successful. With ongoing cost management, it is expected per unit operating expenses will be in the $7.50 per boe range for the remainder of the year. For the nine months ended September 30, 2009 production expenses were $7.35 per boe, down 11 percent compared to the nine months ended September 30, 2008.
Production expenses for the quarter ended September 30, 2009 were $2.5 million, down 26 percent compared to the quarter ended September 30, 2008 due to reduced per unit costs and lower production volumes. For the nine months ended September 30, 2009 production expenses were $8.5 million, down seven percent due to higher production volume offset by lower per unit costs.
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Production expenses Three months ended Nine months ended
September 30, September 30,
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2009 2008 Change 2009 2008 Change
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Production expenses
($000's) 2,452 3,310 (26%) 8,479 9,084 (7%)
Production expenses per
boe $ 6.75 $ 8.76 (23%) $ 7.35 $ 8.25 (11%)
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Transportation costs decreased 16 percent (13 percent on a per boe basis) in the quarter ended September 30, 2009 compared to the quarter ended September 30, 2008 as low natural gas prices have reduced the cost of pipeline fuel costs.
Operating Netback (1)
Operating netback represents the margin realized by the production and sale of petroleum and natural gas exclusive of results from hedging. Third quarter 2009 operating netbacks declined due to lower per boe prices offset partially by lower royalties and operating costs.
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Operating Netbacks Three months ended Nine months ended
($'s per boe) September 30, September 30,
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2009 2008 Change 2009 2008 Change
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Sales price 27.21 62.41 (56%) 30.40 62.99 (52%)
Less:
Royalties 4.35 16.56 (74%) 5.99 15.26 (61%)
Production expenses 6.75 8.76 (23%) 7.35 8.25 (11%)
Transportation charges .78 .90 (13%) .87 1.04 (16%)
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Operating netback 15.33 36.20 (58%) 16.20 38.45 (58%)
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Operating netback including
hedging 16.44 29.29 (44%) 17.03 33.68 (49%)
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(1) non-GAAP measure - refer to discussion on non-GAAP measures below.
General and Administrative Expenses
For the quarter ended September 30, 2009 general and administrative ("G&A") expenses were $1.0 million, down 30 percent compared to the quarter ended September 30, 2008. With lower natural gas prices and cash flows an increased emphasis was placed on reducing G&A costs by focusing on more effective use of consultants, staff and services. For the nine months ended September 30, 2009 G&A expenses were $3.8 million, down nine percent compared to the nine months ended September 30, 2008. Stock based compensation increased slightly in the quarter ended September 30, 2009 compared to the quarter ended September 30, 2008 as options outstanding were consistent over the two periods. For the nine months ended September 30, 2009 stock based compensation was down 39 percent compared to the nine months ended September 30, 2008 because in the 2008 period certain employees voluntarily renounced stock options resulting in a significant one time charge to stock based compensation.
On a per unit basis, for the quarter ended September 30, 2009 G&A costs were $2.83 per boe, down 27 percent from $3.87 per boe for the quarter ended September 30, 2008 primarily due to lower costs offset slightly by lower volume. For the nine months ended September 30, 2008 per unit G&A costs were $3.28 per boe, down 13 percent from $3.78 per boe for the nine months ended September 30, 2008 as cost decreased and volume increased, both contributing to the improved per unit measure. There were no general and administrative costs capitalized for the periods ended September 30, 2009 or 2008.
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General and administrative Three months ended Nine months ended
expenses September 30, September 30,
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2009 2008 Change 2009 2008 Change
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G&A expenses ($000's) 1,028 1,463 (30%) 3,783 4,149 (9%)
G&A expenses per boe $ 2.83 $ 3.87 (27%) $ 3.28 $ 3.78 (13%)
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Stock-based compensation
($000's) 174 168 4% 529 862 (39%)
Stock-based compensation
per boe $ 0.48 $ 0.45 6% $ 0.46 $ 0.79 (38%)
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Interest Expense
For the quarter ended September 30, 2009 interest expense was $0.8 million, up 13 percent compared to $0.7 million for the quarter ended September 30, 2008. Average amounts drawn on the bank operating line were 24 percent higher in the 2009 period which was partially offset by lower interest rates. For the nine months ended September 30, 2009 interest expense was $1.9 million, down 18 percent compared to the nine months ended September 30, 2008. Average amounts drawn on the bank operating line was 14 percent higher in the nine months ended September 30, 2009 compared to the 2008 period which was more than offset by lower interest rates in the 2009 period. Interest rates have declined significantly in 2009 compared to 2008 as recessionary forces have resulted in lower market interest rates.
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Interest Expense Three months ended Nine months ended
September 30, September 30,
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2009 2008 Change 2009 2008 Change
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Interest expenses ($000's) 755 670 13% 1,899 2,332 (19%)
Interest expenses per boe $ 2.08 $ 1.77 17% $ 1.65 $ 2.13 (22%)
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Depletion, Amortization and Accretion
In the quarter ended September 30, 2009 Depletion, Amortization and Accretion ("DA&A") totaled $8.3 million ($22.73 per boe) down nine percent compared to $9.0 million ($23.92 per boe) for the quarter ended September 30, 2008. The per unit depletion rate declined five percent comparing the third quarter of 2009 to the third quarter of 2008 as ongoing drilling success and low cost reserve additions have brought down per unit DA&A rates consistently since the beginning of 2007. For the nine months ended September 30, 2009 DA&A totaled $26.2 million ($22.69 per boe), down six percent and down 11 percent on a per unit basis compared to the nine months ended September 30, 2008 total of $28.0 million ($25.50 per boe).
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Depletion, Amortization Three months ended Six months ended
and Accretion June 30, June 30,
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2009 2008 Change 2009 2008 Change
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DA&A expenses ($000's) 8,261 9,046 (9%) 26,165 27,979 (6%)
DA&A expenses per boe $ 22.73 $23.92 (5%) $ 22.69 $25.50 (11%)
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Income Taxes
The Company does not expect to pay current income tax during 2009 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 September 30, 2009 was $3.6 million ($0.04 per share) compared to net income of $8.2 million ($0.09 per share) in the quarter ended September 30, 2008. The quarter ended September 30, 2008 benefited by a $12.1 million positive swing in the unrealized position on commodity price derivatives in place during the 2008 period.
CAPITAL COSTS
For the quarter ended September 30, 2009 $6.7 million in capital costs were incurred on exploration and production activities, down 52 percent compared to $14.0 million for the quarter ended September 30, 2008. Lower cash flow in the third quarter of 2009 period due mainly to lower commodity prices compared to the third quarter of 2008 resulted in reduced capital spending as the Company continues to limit its capital spending to approximate cash flows. Four wells (2.6 net) were drilled in the quarter ended September 30, 2009 compared to 10 net wells in the quarter ended September 30, 2008.
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Three months ended Nine months ended
($000's) September 30, September 30,
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2009 2008 2009 2008
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Drilling and completion 6,077 10,220 15,396 19,543
Drilling incentive credits (1,257) - (1,257) -
Equipping and tie-ins 987 2,163 3,399 4,707
Land 674 1,465 1,662 3,070
Geological and geophysical 223 141 832 965
Office and other - 7 - 14
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Total cash expenditure 6,704 13,996 20,032 28,299
Asset retirement obligation (82) (39) (129) 350
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Total capital before acquisitions
and dispositions 6,622 13,957 19,903 28,649
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Net acquisitions (dispositions) - - (1,598) -
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Total capital 6,622 13,957 18,305 28,649
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Total cash expenditure 6,704 13,996 20,032 28,299
Abandonment and restoration (128) (58) (231) (186)
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Capital per statement of cash flow 6,576 13,938 19,801 28,113
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For the nine months ended September 30, 2009 $20.0 million in capital costs were incurred to drill eight net wells, down 29 percent compared to the nine months ended September 30, 2008 in which there were 15 net wells drilled. The non-core Karr asset was sold in the first quarter of 2009 for $1.5 million to take advantage of opportunities to high grade the asset base and focus on the three core areas.
Drilling, completion, equip and tie-in activity represented 88 percent of the capital spent in the first nine months of 2009. A $26 million capital budget is planned for 2009, 89 percent of which is targeted toward drilling, completion, equip and tie-in activity. Due to low commodity prices, drilling capital has been limited to wells that are required to be drilled under farm in commitments to earn lands or to extend land tenure where lands are expiring.
Capital will also be directed toward crown land purchases in Pembina to ensure the land and opportunity base is increased. It is expected that 2009 capital spending will be funded by cash flow provided by operating activities and an approximate $3.0 million increase bank borrowings. Drilling credits are earned under a program announced by the Alberta government that will provide credits of $200 per metre of wells drilled between April 1, 2009 and March 31, 2011. An estimated $2.7 million in drilling credits is expected to be earned during 2009. Initial drilling credits were paid by the Alberta government in October 2009.
WORKING CAPITAL
Accounts receivable of $10.5 million at September 30, 2009 were primarily revenue receivables ($4.9 million) and amounts owing from partners ($3.8 million). Accounts payable at September 30, 2009 of $12.7 million were comprised of trade payables for capital and operating costs ($5.6 million), royalties ($1.0 million), amounts owing to partners ($2.6 million) and capital costs accrued at the end of the quarter for ongoing drilling and completion operations ($2.0 million).
Working capital excluding bank indebtedness and the unrealized loss on risk management activities was in a deficit position of $1.2 million at September 30, 2009. 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 deficiency, operations and capital costs with a mix of operating cash flow, drilling credits and debt financing through the bank operating line. An operating bank line was in place for $66 million at September 30, 2009, secured by producing properties. At September 30, 2009, $62.0 million was drawn on the bank line leaving $4.0 million of capacity on the line. The bank line remains at $66 million until January 1, 2010 at which time it reduces by $1.0 million per month until a February 2010 review date. The December 31, 2009 reserves evaluation will then be taken into consideration to re-establish a new, go forward bank line amount. Future capital spending is planned at amounts that can be met with expected operating cash flow, drilling credits and the borrowing capacity within the bank line.
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 Cash flow provided by operating activities and
funds from operations for the periods ended September 30 is as follows:
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Three months ended Nine months ended
($000's) September 30, September 30,
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2009 2008 2009 2008
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Cash flow provided by operating
activities 4,471 17,153 11,877 31,934
Changes in non-cash working capital
items related to operating activities (97) (8,268) 1,909 (1,337)
Cost of abandonment and restoration 128 58 231 186
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Funds from operations 4,502 8,943 14,017 30,783
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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 $0.05 per share (basic and diluted) for the quarter ended September 30, 2009 compared to $0.10 for the quarter ended September 30, 2008. For the nine months ended September 30, 2009 funds from operations per share were $0.15 compared to $0.33 for the nine months ended September 30, 2008. Weaker commodity prices have been the primary cause for the lower funds from operations in the 2009 periods.
RISKS
Primary financial risks relate to volatility of commodity prices. Interest 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 direct, as variations between the regional markets for natural gas are often much greater than can be explained by currency variability. The Province of Alberta announced further changes to royalties for new wells drilled after November 19, 2008 described as the Transitional Royalty Framework. The Province of Alberta announced additional measures in March 2009 that provide for five percent royalties for a one year period on new wells brought on stream after April 1, 2009 and drilling credits of $200 per metre for wells spudded after April 1, 2009 until March 31, 2010. Both incentive programs were subsequently extended by one year until March 31, 2011. The Transitional Royalty Framework and the additional announcements add layers of complexity on the New Royalty Framework implemented on January 1, 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 is exposed to fluctuations in interest rates on its bank loan which charges interest at variable market rates. The Company entered into an interest rate swap transaction effective February 2009 to fix the interest rate on $40.0 million of its variable rate demand bank line. The transaction fixes the interest rate for a two year period at a borrowing rate of 2.39 percent. Including the Company's borrowing margin on its bank line the current all in rate on the $40 million fixed is 5.39 percent. 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 September 30, 2009 results in an unrealized liability of $782,000 (December 31, 2008 - $748,000 liability).
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 marked-to-market position on natural gas hedging contracts in place at September 30, 2009 resulted in an unrealized loss of $952,000 (December 31, 2008 - $114,000 gain). Total realized gains/losses from commodity price risk management activities in the third quarter of 2009 were $707,000 (2008 - $2,637,000 loss) and $959,000 for the nine months ended September 30, 2009 (2008 - $5,238,000 loss).
As at September 30, 2009 the Company has entered into natural gas hedging positions summarized in the following table. All natural gas contracts are priced in Canadian dollars per gigajoule ("GJ"). The price per GJ can be converted to an approximate price per million cubic feet ("MCF") by multiplying the per GJ price by 1.05. GJ volume can be converted to an approximate MCF volume by multiplying the GJ volume by 0.95.
Natural Gas Risk Management Contracts ---------------------------------------------------------------------------- Daily quantity Term of Contract Fixed price per gigajoule (GJ/day) (Cdn$/GJ) ---------------------------------------------------------------------------- 2,000 June 1 to December 31, 2009 $3.40 floor/$5.00 ceiling ---------------------------------------------------------------------------- 2,000 July 1 to December 31, 2009 $3.435 floor/$5.00 ceiling ---------------------------------------------------------------------------- 2,000 August 1, 2009 to March 31, 2010 $4.00 fixed price swap ---------------------------------------------------------------------------- 2,000 August 1, 2009 to March 31, 2010 $4.16 fixed price swap ---------------------------------------------------------------------------- 2,000 August 1, 2009 to March 31, 2010 $4.18 fixed price swap ---------------------------------------------------------------------------- Subsequent to September 30, 2009 the following additional risk management contracts were put in place. ---------------------------------------------------------------------------- Daily quantity Term of Contract Fixed price per gigajoule (GJ/day) (Cdn$/GJ) ---------------------------------------------------------------------------- 2,000 April 1, 2010 to March 31, 2011 $6.02 fixed price swap ---------------------------------------------------------------------------- 2,000 April 1, 2010 to December 31, 2011 $6.00 fixed price swap ----------------------------------------------------------------------------
Absent risk management contracts, the effects of changes in commodity prices on annual cash flow before working capital changes are summarized in the following table based on estimated production of 4,000 boe/d.
---------------------------------------------------------------------------- Commodity Price change Cash flow change ($ 000's) ---------------------------------------------------------------------------- Natural gas ($/mcf) 1.00 4,000 ---------------------------------------------------------------------------- Oil and Liquids ($/bbl) 10.00 1,270 ----------------------------------------------------------------------------
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 September 30, 2009 were $22,000 (2008 - $68,000) and for the nine months ended September 30, 2009 were $157,000 (2008 - $230,000).
SHARE DATA
As of the date of this MD&A the Company had 93,547,064 issued and outstanding common shares. Additionally, as at September 30, 2009 options to purchase 7,522,000 common shares have been issued.
DISCLOSURE CONTROLS AND PROCEDURES OVER FINANCIAL REPORTING
The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's Chief Executive Officer and Chief Financial Officer by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's disclosure controls and procedures at the financial year end of the Company and have concluded that the Company's disclosure controls and procedures have not changed to the end of the third quarter of 2009 for the foregoing purposes.
INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company's Chief Executive Officer and Chief Financial Officer have designed, or caused to be designed under their supervision, internal control over financial reporting to provide reasonable assurance regarding the reliability of the Company's financial reporting and the preparation of financial statements for external purposes in accordance with the Canadian GAAP. The control framework the Company's officers have used to design the issuer's ICFR is the COSO financial framework. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the Company's internal control over financial reporting at December 31, 2008 and concluded that the Company's internal control over financial reporting is effective, at the financial year end of the Company, for the foregoing purpose the Company is required to disclose herein any change in the Company's internal control over financial reporting that occurred during the period beginning on December 31, 2008 and ended on September 30, 2009 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. No material changes in the Company's internal control over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
It should be noted that a control system, including the Company's disclosure and internal controls and procedures over financial reporting, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
RISKS AND UNCERTAINTIES, CRITICAL ACCOUNTING ESTIMATES AND RECENT ACCOUNTING PRONOUNCEMENTS
The MD&A is based on the 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
Credit Risk and Fair Value of Financial Assets and Financial Liabilities
Effective January 1, 2009, the Company adopted the Emerging Issues Committee of the CICA issued Abstract #173, "Credit Risk and the Fair Value of Financial Assets and Financial Liabilities", concerning the measurement of financial assets and financial liabilities. The new policy assesses an entity's own credit risk and the credit risk of the counterparty when determining the fair value of financial instruments. The effect that the implementation had on the Company's financial position in the current quarter was a reduction in unrealized hedging losses of $131,000 and a corresponding decrease in unrealized interest rate risk management expense. An adjustment was not made to the December 31, 2008 unrealized interest rate hedging loss as it was deemed to be not material.
FUTURE ACCOUNTING PRONOUNCEMENTS
International Financial Reporting Standards
In February 2008, the Canadian Accounting Standards Board confirmed that the use of International Financial Reporting Standards ("IFRS") will be required in 2011 for publicly accountable profit-oriented enterprises. IFRS will replace Canada's current GAAP for listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. Companies will be required to provide one year of comparative data in accordance with IFRS.
In the second quarter of 2008 the Company began to develop its IFRS changeover plan. Initial activities include training sessions and acquisition of written standards and examples of IFRS disclosure to identify where key differences between Canadian GAAP and IFRS exist. A key determination that has significant effect on the financial statements will be the identification of cash generating units within the Company's production properties which are currently considered as a whole.
Based on analysis to date, four CGU's have been identified. Capital assets are also being analyzed for possible componentization. Analysis is being completed using December 31, 2008 property plant and equipment balances to assess the potential IFRS 1 adjustments to be made on conversion. The Company intends to disclose its convergence plan and qualitative effects of IFRS on its financial statements as they become more fully developed.
Financial Instruments - Disclosures
In June 2009, the Accounting Standards Board amended Section 3862, Financial Instruments - Disclosures to converge with Improving Disclosures about Financial Instruments (Amendments to IFRS 7). The amendments expand the disclosures required in respect of recognized fair value measurements and clarify existing principles for disclosures about the liquidity risk associated with financial instruments. This standard will be effective for the annual period ending December 31, 2009. The Company expects to have derivative instruments outstanding at December 31, 2009 and will follow the amended Section 3862 disclosure.
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, 2008 available on SEDAR (www.SEDAR.com) and on our website (www.berensenergy.com).
OUTLOOK
Berens has established drilling plays that are repeatable and low risk. Spending within cash flow has been a discipline that has been adhered to since early 2006 and consistent growth has been demonstrated since that time in both strong and weak commodity price periods. While natural gas prices were weaker early in 2009 focus has been on building the land and drilling inventory base and preparing to test the Cardium light oil potential in Pembina. A disciplined approach to cost management has achieved significant reduction in our costs supported by moderation in the overall industry cost structure.
Capital spending for 2009 is budgeted at $26 million and is planned to be funded with cash flow from operations supplemented by drilling credits and an increase in our line of credit. Capital spending for 2009 continues to be focused in Pembina where we have our strongest economic prospects and the reserve life of new wells is longest. Capital will also be spent on crown land sales to ensure that an extensive drilling inventory is maintained.
A successful light oil well in the Cardium zone using horizontal well and multi-frac technologies was drilled and completed in October and put on production in November. The success of this well establishes proof of an exciting new play in Pembina on existing lands. Berens has approximately 68 sections (38 net) of Cardium rights on the flank of the largest Cardium oil field in central Alberta. A second Cardium well is currently being completed and tested with four more Cardium horizontal wells planned by the end of the first quarter of 2010.
With an extensive land base in Pembina we now have two significant plays in the region on overlapping lands. Liquids rich natural gas drilling has delivered low cost reserves for the Company for the past three years and will continue to be a significant part of future drilling. Added to the natural gas drilling inventory is new potential in the Cardium light oil resource play and the ability to selectively drill oil or natural gas targets depending on commodity prices and potential economic return.
Berens Energy Ltd.
Balance Sheets - unaudited
As at,
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September 30, December 31,
(000's) 2009 2008
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ASSETS (note 6)
Current
Cash $ 786 $ 1
Accounts receivable 10,545 12,854
Unrealized gain on risk management (note 10) - 114
Prepaid expenses and deposits 237 300
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