TIDMAN26
The following amendment should be made to the Talisman Energy Inc. 'Notice of Results' announcement released at 16.55 GMT on February 11, 2010.
The original announcement was released in the incorrect order. The headline should have been 'Unaudited Results for 2009' instead of 'Notice of Results'
All other details remain unchanged.
The full corrected version is shown below.
UNAUDITED RESULTS FOR 2009
TALISMAN ENERGY REPORTS $4 BILLION IN CASH FLOW RESERVE REPLACEMENT COSTS DOWN BY 43% RAMPING UP SHALE ACTIVITY
Talisman Energy Inc. reported its operating and financial results for 2009:
-- Cash flow1 was $4 billion, down 36% from 2008, primarily due to lower commodity prices. Cash flow in the fourth quarter was $921 million, down 41% from a year earlier, but up 10% compared to the previous quarter;
-- Net income was $437 million, down from $3.5 billion in 2008. The company recorded a loss of $111 million for the quarter;
-- Earnings from continuing operations1 were $640 million versus $2.3 billion a year ago. The total for the fourth quarter was $76 million;
-- Talisman completed non-core asset sales with proceeds of approximately $2.7 billion;
-- Capital spending was $4.3 billion, down from $5.2 billion in 2008;
-- Net debt1 at year end was $2.1 billion, down from $3.9 billion a year earlier;
-- Production from continuing operations increased 2% over 2008 to 413,000 boe/d. Total production averaged 425,000 boe/d, down 2% due to asset sales;
-- The company replaced 162% of 2009 production with proved reserves, excluding divestitures, and 112% through drilling and non-price revisions;
-- Reserve replacement costs were $24.30/boe (excluding price revisions), and $19.72/boe excluding land and price revisions;
-- The company spent $1.4 billion on shale plays in North America, adding substantial acreage and progressing development of the Pennsylvania Marcellus and Montney shale programs;
-- The company set a new production record in Southeast Asia, volumes increased 18% with completion of the Northern Fields development and increased contract takes at Corridor;
-- In January 2010, Talisman acquired an interest in the Jambi Merang PSC in Indonesia;
-- In the North Sea, first production from the Rev Field was achieved early in 2009 and the company progressed field developments at Yme, Auk North, Auk South and Burghley;
-- Talisman completed a number of transactions to acquire a large exploration position in Papua New Guinea (PNG); and
-- The company made exploration discoveries in the North Sea, Colombia and the Kurdistan region of northern Iraq and successfully appraised the Situche discovery in Peru.
1 The terms "cash flow", "earnings from continuing operations" and "net debt" are non-GAAP measures. Please see the advisories and reconciliations elsewhere in this press release.
"We continued to make significant progress on strategic implementation through 2009, despite the volatile commodity price environment," said John A. Manzoni, President and CEO. "Over the past 18 months, we have been restructuring and repositioning Talisman, focusing the portfolio, upgrading both the quality of assets and the growth potential of the company. 2010 will be an important transition year as we cycle increasing amounts of capital into developing our shale plays in North America.
"A major objective of the strategy is to improve returns through lower reserve replacement costs. We've started to see evidence of this in 2009, largely as a result of successful shale drilling programs. Our proved reserve replacement cost in 2009 was $24.30/boe, 43% lower than 2008 and 25% lower than our three year rolling average. Excluding land expenditures in 2009, this number is below $20/boe.
"We replaced 112% of production in 2009 through drilling and non-price revisions, with 173 mmboe of proved reserve additions, excluding the impact of asset sales. Including the impact of price and other revisions, the number was 251 mmboe or 162%. In North America, we replaced 210% of production with proved reserve additions through drilling.
"With lower oil and natural gas prices brought on by the economic downturn, we saw netbacks fall by over 40% in 2009, and these lower commodity prices had a substantial impact on our financial results.
"Cash flow for the year was approximately $4 billion, versus $6.2 billion a year earlier, reflecting lower commodity prices, although we were helped by cash proceeds from derivative contracts, and lower taxes and royalties. Cash flow in the fourth quarter was $921 million, down from 2008, but up 10% from the third quarter with higher production volumes and commodity prices.
"Reflecting this trend, earnings from continuing operations came in at $640 million versus $2.3 billion, and net income was $437 million, also down sharply, from $3.5 billion a year earlier. We recognized $1.7 billion of gains on our held for trading financial instruments in 2008, compared to a loss of approximately $400 million in 2009. However we generated approximately $1 billion in cash proceeds from these instruments during 2009.
"Production from continuing operations increased 2% to 413,000 boe/d, and our actual production rate for the year was 425,000 boe/d. However, we sold 30,000 boe/d of non-core assets over the course of the year, which lowered total volumes in 2009 by about 15,000 boe/d.
"These sales generated $2.7 billion in proceeds, with metrics of approximately $80,000 per boe per day. The divestment program helped focus our portfolio and strengthen the balance sheet. As a result, we are in strong financial shape with year end net debt at $2.1 billion, compared to $3.9 billion at December 31, 2008.
"Capital spending came in at $4.3 billion, with approximately one-third ($1.4 billion) directed at North American shale programs. Talisman added substantial amounts of acreage in the Pennsylvania Marcellus and Montney shale plays, where we now have approximately 4,800 net drilling locations in our Tier 1 acreage.
"We participated in 66 net shale pilot and development wells, moving the Pennsylvania Marcellus, and two areas within the Montney shale, to commercial development. We expect to exit 2010 with Pennsylvania producing between 250-300 mmcf/d as we ramp up to 10 rigs, and recent well results are coming in better than planned. Pilot work also continues in Quebec.
"We have taken significant steps towards reshaping and strengthening our international exploration portfolio. We have built a strategic land position in PNG through a series of acquisitions, and now have interests in over eight million net acres, as part of a strategy to aggregate significant gas reserves. We also acquired additional exploration acreage within our core operating areas in the North Sea and Southeast Asia, as well as in South America and the Kurdistan region of northern Iraq.
"In the North Sea, we made exploration discoveries at Grevling, Shaw and Godwin, and development options are being evaluated. We also made gas condensate discoveries in Colombia and the Kurdistan region of northern Iraq and drilled a successful appraisal well in Peru.
"In Southeast Asia, the company continues to pursue its successful growth strategy, setting a new production record with completion of the Northern Fields development in Malaysia/Vietnam and increased gas sales at Corridor in Indonesia. Talisman continues to progress development plans for the HSD/HST fields in Vietnam. Talisman and its working interest partners approved sanction of the Kitan discovery in December 2009 and are awaiting approval from the Timor Leste/Australia Authority. We've also recently acquired an interest in the Jambi Merang PSC in Indonesia, near the Corridor gas field.
"In the North Sea, the majority of our development capital program was directed toward progressing the Yme, Burghley, Auk North and Auk South field developments, which will come onstream in the 2010 to 2012 time frame. We commissioned the Rev Field in Norway, with a significant ramp up in production over the course of the year. The company also drilled a number of successful development wells, including three in the Varg field.
"In summary, the transition of our portfolio is on track. We ended the year with a more focused portfolio and a strong balance sheet. We are on a path to transition into higher return, longer-term production growth from shale, and we will continue to step up our investments into shale programs over the next few years. Our investment plan this year reflects that transition, and we will maintain flexibility to ensure we can execute against it."
Financial Results
The financial information contained in this release is unaudited. The company will file its audited Financial Statements for the year ended December 31, 2009, along with the related Management's Discussion and Analysis, Annual Information Form and Annual Report on Form 40-F by March 8, 2010.
The company announced its capital spending plans for 2010 on January 11, 2010. For additional information related to this press release, please visit Talisman's website at www.talisman-energy.com.
Three months ended Year ended
December 31 2009 2008 2009 2008
Cash flow ($ million) 921 1,565 3,961 6,163
Cash flow per share2 0.91 1.54 3.90 6.06
Net income (loss) ($ million) (111) 1,202 437 3,519
Net income (loss) per share (0.11) 1.18 0.43 3.46
Earnings from continuing 76 502 640 2,330
operations ($ million)
Earnings from continuing 0.07 0.49 0.63 2.29
operations per share 2
Average shares outstanding (million) 1,015 1,015 1,015 1,017
Lower commodity prices had a significant impact on Talisman's 2009 financial results. WTI oil prices averaged approximately US$62/bbl in 2009, down 38% from the 2008 average of US100/bbl. North American natural gas prices also decreased from 2008 with NYMEX and AECO natural gas prices down 55% and 51%, respectively.
Cash flow for 2009 was $4 billion versus $6.2 billion a year earlier. Relative to 2008, lower oil and gas prices contributed to most of the decrease, offset partially by lower cash taxes ($655 million), royalties ($846 million) and higher realized gains on held-for-trading financial instruments ($547 million). Cash flow increased 10% to $921 million compared to the third quarter, with higher production volumes and netbacks.
Earnings from continuing operations, which exclude non-operational items, were $640 million, compared to $2.3 billion a year earlier, again reflecting lower commodity prices.
Net income was $437 million versus $3.5 billion in 2008 impacted by the loss on held for trading financial instruments of $412 million in 2009, compared to a gain of $1.7 billion in 2008, primarily as prices increased through the year and Talisman's hedges rolled forward. The company recorded a loss of $111 million in the fourth quarter, compared to net income of $1.2 billion in 2008, again largely reflecting changes in amounts recognized on held for trading financial instruments.
The company's DD&A expense decreased in the fourth quarter of 2009 and for the full year as a whole, due principally to the requirement in 2008 to use year-end prices to calculate reserves, which resulted in one property in the UK and one property in Norway having no proved reserves. As a consequence, the net book value of these properties of approximately $410 million in the UK and approximately $90 million in Norway was charged to DD&A in the fourth quarter of 2008.
Capital expenditures totalled $4.3 billion, including discontinued operations and non-cash capital lease costs. Talisman spent $4.1 billion on exploration and development in continuing operations during 2009, a decrease from $4.8 billion in 2008. North America accounted for 44% of spending, North Sea development 26%, Southeast Asia development 11% and international exploration 18%.
The company strengthened its balance sheet, reducing net debt to $2.1 billion, down from $3.9 billion in 2008, principally due to the sale of non-core assets.
2 The terms "cash flow per share" and "earnings from continuing operations per share" are non-GAAP measures. Please see the advisories and reconciliations elsewhere in this press release.
Production
Three months ended Year ended
December 31 2009 2008 2009 2008
Total oil and liquids (bbls/d) 203,000 227,000 211,000 224,000
Total natural gas (mmcf/d) 1,320 1,228 1,283 1,247
Continuing operations (boe/d) 418,000 407,000 413,000 403,000
Discontinued operations (boe/d) 5,000 25,000 12,000 29,000
Total production (boe/d) 423,000 432,000 425,000 432,000
Production from continuing operations averaged 413,000 boe/d, 2% above 2008; total production for the year was down 2% to 425,000 boe/d, as a result of asset sales. Production from continuing operations increased 6% compared to the prior quarter with increasing shale gas production and the completion of maintenance turnarounds.
North American natural gas production declined with less conventional drilling activity and natural declines, partially offset by increasing production in the Pennsylvania Marcellus and Montney shale, as well as successful development in the Outer Foothills.
Production from continuing operations in the UK averaged 89,000 boe/d for the year, 7% lower than 2008 as a result of maintenance and repair work, and natural declines. In Scandinavia, production increased from the prior year with first production from the Rev field and development drilling at Varg and Brage. Talisman set a new production record in Southeast Asia with completion of the Northern Fields development and increased contract takes at Corridor.
Netbacks
Three months ended Year ended
December 31 2009 2008 2009 2008
($/boe)
Sales 55.51 48.45 49.40 76.03
Hedging loss - - - (0.17)
Royalties 9.13 8.05 7.34 13.62
Transportation 1.64 1.14 1.43 1.34
Operating expenses 12.84 13.29 12.91 13.57
Netback 31.90 25.97 27.72 47.33
Oil and liquids netback ($/bbl) 44.68 25.40 37.49 59.01
Natural gas netback ($/mcf) 3.35 4.46 3.02 5.78
In 2009, the company's average netback was $27.72/boe, 41% lower than 2008, due principally to lower commodity prices in 2009, partially offset by decreases in royalties. Fourth quarter netbacks were up 23% from the same quarter in 2008, averaging $31.90/boe, and 17% above the third quarter of 2009.
Royalty expense was $1.2 billion in 2009, a 42% decrease from 2008, reflecting lower commodity prices. The company's average royalty rate was 15%, a decrease of 3% compared to 2008.
Total operating costs for the company were $2 billion during 2009, relatively consistent with 2008. On a per unit basis, costs decreased 5% to $12.91/boe from the previous year, due mainly to a 4% decrease in the UK and a 17% decrease in Scandinavia.
Proved Gross Reserves
Proved Gross Reserves
Average 2009 Pricing
mmboe
December 31, 2008 1,434.3
Discoveries, extensions and additions 172.6
Revisions and transfers 1.2
Price revisions 77.1
Net acquisitions and dispositions ( 119.5 )
Production ( 155.0 )
December 31, 2009 1,410.7
The company added 251 mmboe of proved gross reserves in 2009 (before asset sales), replacing the equivalent of 162% of annual production. Of the total increase, 77 mmboe (31%) was due to higher prices (average 2009 prices versus year end 2008 prices, using the new SEC rules). Excluding the impact of price changes, the company replaced 112% of production. Total reserves fell by 2% due to non-core asset sales.
At year end 2009, Talisman had 865 mmboe of probable reserves, an increase of 13% from 2008.
In North America, the company replaced 210% of production (129 mmboe) with proved gross reserves through drilling, with 90 mmboe coming from the Marcellus shale. Proved undeveloped reserves (PUDs), account for approximately 26% of total proved reserves in North America.
Internationally, the company replaced 144% of production, including price revisions. No proved reserves were booked for PNG at year end. International reserve additions can be highly variable because they depend on development approval before discoveries can be moved to the proved reserves category.
At year end 2009, the company had approximately 400 mmboe of PUDs, which accounted for 28% of total proved reserves. Of these PUDs, 38% were in North America and 62% were international.
Proved reserve replacement costs averaged $24.30/boe in 2009, compared to $42.87/boe in 2008 and a three year rolling average of $32.38/boe (excluding price impacts).
North America
Production from continuing operations averaged approximately 158,000 boe/d in 2009, a 4% decrease over 2008, due to natural declines and reduced conventional drilling. Natural gas production from continuing operations averaged 788 mmcf/d.
Talisman spent $1.4 billion on shale gas programs in North America, including land, development, infrastructure and drilling. In November 2009, the company announced it had spent $570 million to acquire 170,000 net acres of high quality land in the Pennsylvania Marcellus and Montney shale plays, which now have a potential 4,800 net drilling locations. Talisman now has interests in approximately two million net shale acres.
In the Pennsylvania Marcellus area, the company drilled 53 gross (45.5 net) wells, 38 operated and 15 non-operated. At year end, 27 wells were on production, exiting the year at 65 mmcf/d (December average). Six drilling rigs are currently operating, with plans to increase this up to 10 rigs by year end (drilling up to 170 net wells) with a planned exit rate of between 250-300 mmcf/d.
Talisman continued to progress its Montney shale gas play in 2009. The company drilled 16 gross (15 net) wells, 15 of which were operated and one non-operated. Thirteen wells have been completed to date, of which nine were onstream at year-end, including five horizontal wells that were successfully completed, tested and tied in during the fourth quarter. Total production at year end was 14 mmcf/d (December average), with an expected 2010 exit rate between 40-60 mmcf/d.
Talisman is continuing its pilot program in Quebec where the company holds rights to 756,000 net acres. The company completed the earning phase of its drilling program in Quebec during 2009. The company drilled two horizontal wells in Quebec in 2009 and is currently drilling a third horizontal well. Talisman expects to drill a fourth horizontal well this year, testing all four wells in 2010.
Production from Talisman's conventional areas was 976 mmcfe/d. In total, 64 gross (39 net) wells were drilled in 2009, with excellent results in the Outer Foothills.
Talisman continued to focus its operations, completing sales of non-core midstream assets in Alberta and non-strategic properties in southeast Saskatchewan and southern Alberta. Talisman is evaluating additional sales of conventional assets, depending on market conditions. During 2009, Talisman restructured its North American operations into Conventional and Shale Gas businesses.
UK
Production from continuing operations in the UK averaged 89,000 boe/d, a 7% decrease from 2008. Reductions from a number of fields, due to planned and unplanned shutdowns and declines, offset the reinstatement of Galley and Petronella in 2009, as well as the startup of the Affleck field in August.
The company spent approximately $530 million on development in the UK, with just under half directed at the Auk North and Auk South projects. Additional spending during the year included progressing the Burghley development, completing the Scapa Production Riser Upgrade project and drilling seven development wells.
In the Central North Sea, the Auk North development is underway and two wells were drilled during the year. Auk North is expected to come onstream in 2011. The Auk South redevelopment is also progressing with detailed engineering completed during 2009. First production is expected in 2012.
During the year, the Tweedsmuir Phase 3 water injection development project was completed. The company also progressed the Burghley development, installing the riser and drilling a development well. The subsea and topside facilities will be completed in 2010, with first oil scheduled towards the end of the year.
In January 2009, the company sold its assets in the Netherlands, with proceeds of approximately $600 million.
Scandinavia
Production from continuing operations in Scandinavia averaged 44,000 boe/d for 2009, a 26% increase over 2008, mainly due to increased volumes from Varg and the Rev Field, which came onstream in January. The company spent approximately $530 million on development in Scandinavia during 2009, with approximately 75% directed at the Yme development. A total of eight development wells were drilled in Scandinavia during the year, with an additional four wells drilling at year end.
Development of the Yme Field in the Norwegian Continental Shelf continued throughout year. The company completed the first phase of drilling in the fourth quarter, including three horizontal producers and two water injector wells. First oil from Yme is expected in the second half of 2010. Talisman completed the sale of a 10% interest in the Yme field during 2009.
In the Varg Field, three successful wells were completed in 2009, increasing average net production from 7,500 boe/d in the third quarter to 18,000 boe/d in December.
At Brage, a new oil producer and a new water injector well were completed in 2009, with net oil production averaging 10,800 boe/d at year end. A new development well has been completed more than two months ahead of plan and it is expected to be on production in February 2010.
Production performance improved significantly at the Rev Field, which came onstream early in 2009, increasing from 6,500 boe/d in the third quarter to 23,000 boe/d (net) in fourth quarter.
Southeast Asia
Production from continuing operations in Southeast Asia averaged 108,000 boe/d, an increase of 18% over 2008. The main production increases came from a full year of gas production from the Northern Fields in PM-3 CAA, first oil from the Northern Fields and additional gas sales in Indonesia. There were also increased volumes from the incremental oil recovery program in the Southern Fields, a full year of production from Song Doc, a new infill well in Australia and first production from Tangguh.
In Malaysia, overall production was 31,600 boe/d, up 1% from 2008, but production from the PM-3 CAA increased 14%. Talisman spent $326 million, approximately half of total spending in Southeast Asia to complete the Northern Fields development, including 17 total development wells and one exploration well.
Indonesian production was approximately 66,500 boe/d, 19% higher than 2008, with record production from Corridor due to higher contract takes. In January 2010, Talisman acquired a 25% interest in the onshore Jambi Merang Block where development is underway. Talisman drilled three exploration and 23 development wells in 2009.
Production in Vietnam in 2009 averaged 4,800 bbls/d from Block 46/02. The Government of Vietnam approved reserves assessments for the Hai Su Trang (HST) and Hai Su Den (HSD) fields within Block 15-2/01 and a declaration of commerciality occurred early in the year. The company chose to write off a number of exploration/appraisal wells during 2009, all outside of the development area. These wells encountered hydrocarbons but were not commercial. Talisman has taken this into account and is reviewing the timing of sanction for development of the HST field and an early production scheme for the HSD discovery.
Production in Australia was 5,160 boe/d, 66% higher than 2008. Talisman and its working interest partners approved sanction of the Kitan discovery in December and are waiting approval from the Timor Leste/Australia Authority.
Other
In Talisman's other areas, production from continuing operations during the year averaged 14,000 boe/d, a decrease of 7% from 2008, due to OPEC restrictions. Talisman sold its interests in Trinidad and Tobago and announced the intention to sell assets in Tunisia.
International Exploration
International exploration spending during the year was approximately $755 million, with a number of significant discoveries, in addition to building a highly prospective acreage position in PNG.
Over the course of the year, the company entered into a number of agreements to acquire interests in 10 onshore exploration blocks in the western province of PNG. Four onshore exploration wells are planned this year as the company pursues its gas aggregation strategy. The company now holds interests in 12 blocks covering in excess of eight million net acres subject to regulatory approval.
In Vietnam, Talisman drilled three appraisal wells adjacent to the HSD discovery and farmed-in to two deep water exploration blocks in the Nam Con Son Basin. Blocks 133 and 134 cover approximately 3.3 million acres.
Talisman was awarded the Andaman III block, offshore Indonesia. The block, which is approximately 2.1 million acres in size, is an under-explored, deep water block. Talisman was also awarded two offshore Sabah blocks in Malaysia covering in excess of 3.2 million acres in water depths less than 300 feet.
In the UK, Talisman made discoveries at Godwin and Shaw in the Central North Sea. Pre-engineering work is underway as the company looks to develop these discoveries, along with the Cayley discovery made in late 2007, via the Talisman operated Montrose/Arbroath facilities.
In Norway, Talisman made a discovery at Grevling and an appraisal well is planned for 2010. The company also increased its acreage holdings in the Barents Sea, through the 20th Licence Round and an acreage swap.
The Situche discovery on Block 64 in Peru was successfully appraised in 2009 and drilling was ongoing at year end. In April 2009, Talisman was awarded a 55% working interest in Block 158 in Peru.
Talisman made a significant gas condensate discovery in the Niscota Block in the Colombian Andes Foothills. The Huron-1 well encountered several reservoirs and tested one zone at 3,400 boe/d. In January 2009, Talisman was awarded a 100% working interest in Block 9.
In the Kurdistan region of northern Iraq, the Kurdamir-1 well in Block 44 discovered significant amounts of gas condensate in an upper zone. The well was drilling towards a deeper target at year end. In June 2009, Talisman acquired an interest and operatorship in Block K9.
Talisman Energy Inc. is a global, diversified, upstream oil and gas company, headquartered in Canada. Talisman's three main operating areas are North America, the North Sea and Southeast Asia. The Company also has a portfolio of international exploration opportunities. Talisman is committed to conducting business safely, in a socially and environmentally responsible manner, and is included in the Dow Jones Sustainability (North America) Index. Talisman is listed on the Toronto and New York Stock Exchanges under the symbol TLM. Please visit our website at www.talisman-energy.com.
For further information, please contact:
Media and General Inquiries: Shareholder and Investor Inquiries:
David Mann
Vice President, Corporate Christopher J. LeGallais
& Investor Communications Vice President, Investor Relations
Phone: 403-237-1196 Phone: 403-237-1957 Fax: 403-237-1210
Fax: 403-237-1210
E-mail: E-mail: tlm@talisman-energy.com
tlm@talisman-energy.com
03-10
Forward-Looking Information
This news releasecontains information that constitutes "forward-looking information" or "forward-looking statements" (collectively "forward-looking information") within the meaning of applicable securities legislation. This forward-looking information includes, among others, statements regarding:
-- expected production growth and returns arising from shale;
-- maintenance of flexibility in relation to the investment plan;
-- expected Pennsylvania production volumes and drilling;
-- expected onstream dates of North Sea developments;
-- expected medium term growth, and longer-term production growth from shale;
-- anticipated filing dates of financial statements, management discussion & analysis, the annual information form, and the annual report;
-- the expected 2010 exit rate for the Montney shale gas play;
-- planned drilling in Quebec;
-- planned sales of conventional assets;
-- expected first oil from, and completion of facilities at, the Burghley development;
-- expected first oil from the Yme Field;
-- expected production timeframe of a new development well at Brage;
-- the intention to sell assets in Tunisia;
-- planned onshore exploration wells in PNG;
-- planned development at Godwin, Shaw, and the Cayley discovery; and
-- the planned Grevling appraisal well.
The following material assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information contained in this news release. Talisman has set its 2010 capital expenditure plans assuming: (1) Talisman's production in 2010 will be broadly the same as 2009 at around 425,000 boe/d excluding any sales in North America during the year; (2) a US$60/bbl WTI oil price, and (3) a US$3.50/mmbtu NYMEX natural gas price. Information regarding business plans generally assumes that the extraction of crude oil, natural gas and natural gas liquids remains economic.
Undue reliance should not be placed on forward-looking information. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Talisman and described in the forward-looking information contained in this news release. The material risk factors include, but are not limited to:
-- the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas, market demand and unpredictable facilities outages;
-- risks and uncertainties involving geology of oil and gas deposits;
-- uncertainty related to securing sufficient egress and markets to meet shale gas production;
-- the uncertainty of reserves and resources estimates, reserves life and underlying reservoir risk;
-- the uncertainty of estimates and projections relating to production, costs and expenses;
-- the impact of the economy on the ability of the counterparties to the Company's commodity price derivative contracts to meet their obligations under the contracts;
-- potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
-- fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;
-- the outcome and effects of any future acquisitions and dispositions;
-- health, safety and environmental risks;
-- uncertainties as to the availability and cost of financing and changes in capital markets;
-- risks in conducting foreign operations (for example, political and fiscal instability or the possibility of civil unrest or military action);
-- changes in general economic and business conditions;
-- the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; and
-- results of the Company's risk mitigation strategies, including insurance and any hedging activities.
The foregoing list of risk factors is not exhaustive. Additional information on these and other factors, which could affect the Company's operations or financial results are included in the Company's most recent Annual Information Form. In addition, information is available in the Company's other reports on file with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC). Forward-looking information is based on the estimates and opinions of the Company's management at the time the information is presented. The Company assumes no obligation to update forward-looking information should circumstances or management's estimates or opinions change, except as required by law.
Reserves Information
Talisman's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to Talisman by Canadian securities regulatory authorities, which permits Talisman to provide certain disclosure in accordance with US disclosure requirements. The primary differences between the US disclosure requirements and the Canadian disclosure standards under National Instrument 51-101 ("NI 51-101") are that (i) SEC rules require disclosure only of proved reserves, whereas NI 51-101 requires disclosure of proved and probable reserves (ii) SEC rules require reserves to be cash flow positive on an undiscounted basis, whereas NI 51-101 requires reserves to show a hurdle rate of return; and (iii) SEC rules require that reserves and the associated future net revenue be estimated using historic average annual prices, whereas NI 51-101 requires disclosure of reserves and the associated future net revenue using forecast prices. The information provided by Talisman in this news release may differ from the corresponding information prepared in accordance with NI 51-101 standards. Talisman's proved and probable reserves, using SEC annual average pricing methodology, have been estimated using the standards contained in Regulation S-X of the SEC, which requires that proved and probable reserves be estimated using existing economic and operating conditions. US practice is to disclose net reserves after the deduction of estimated royalty burdens. Talisman makes additional voluntary disclosure of gross reserves.
The exemption granted to Talisman also permits it to disclose internally evaluated reserves data. Any reserves data contained in this news release reflects Talisman's estimates of its reserves. No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data disclosed in this news release.
Reserves Replacement Ratio
The reserves replacement ratios (before net acquisitions and dispositions) were calculated by dividing the sum of changes (revisions of estimates and discoveries) to estimated gross proved oil and gas reserves during 2009 by the Company's 2009 gross production. The Company's management uses reserves replacement ratios as an indicator of the Company's ability to replenish annual production volumes and grow its reserves. It should be noted that a reserves replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely, based on the extent and timing of new discoveries, project sanctioning and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not include cost, value or timing of future production of new reserves, it cannot be used as a measure of value creation.
Reserve Replacement Costs
In this news release, Talisman discloses reserve replacement costs. Reserve replacement costs are used by the Company to determine the cost of reserves additions in a period. Talisman's reported reserves replacement costs may not be comparable to similarly titled measures used by other companies. Reserves replacement costs may not reflect full cycle reserves replacement costs. Reserves replacement costs' predictive and comparative value is limited for the aforementioned reasons. Reserves replacement costs are calculated by dividing exploration and development capital spending (including discontinued operations, but excluding midstream) by proved reserve additions (excluding price revisions). The reserves replacement cost in 2008 was $42.87/boeand in 2007 was $33.69/boe. The average reserves replacement cost for 2009, 2008, and 2007 was $32.38/boe.
Netbacks
Talisman also discloses its Company netbacks in this news release. Netbacks per boe are calculated by deducting from sales price associated royalties, operating and transportation costs.
Gross Production
Throughout this news release, Talisman makes reference to production volumes. Such production volumes are stated on a gross basis, which means they are stated prior to the deduction of royalties and similar payments. In the US, net production volumes are reported after the deduction of these amounts. US readers may refer to the table headed "Continuity of Proved Net Reserves" in Talisman's most recent Annual Information Form for a statement of Talisman's net production volumes by reporting segment that are comparable to those made by US companies subject to SEC reporting and disclosure requirements.
Boe Conversion
Throughout this news release, barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil and is based on an energy equivalence conversion method. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Canadian Dollars and GAAP
Dollar amounts are presented in Canadian dollars, except where otherwise indicated. Unless otherwise indicated, the financial information is set out in accordance with Canadian GAAP which may differ from U.S. GAAP.
Non-GAAP Financial Measures
Included in this news release are references to financial measures used in the oil and gas industry such as cash flow, earnings from continuing operations and net debt. These terms are not defined by GAAP in either Canada or the U.S. Consequently, these are referred to as non-GAAP measures. Talisman's reported results of cash flow, earnings from continuing operations and net debt may not be comparable to similarly titled measures reported by other companies. Cash flow represents net income before exploration costs, DD&A, future taxes and other non-cash expenses. Cash flow is used by the Company to assess operating results between years and between peer companies using different accounting policies. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with Canadian GAAP as an indicator of the Company's performance or liquidity. Cash flow per share is cash flow divided by the average number of common shares outstanding during the period. A reconciliation of cash provided by operating
activities to cash flow follows.
Cash Flow December 31, 2009 C$ million, except per share amounts
Three Months ended Year ended
December 31 2009 2008 2009 2008
Cash provided by operating activities 624 1,569 3,599 6,154
Changes in non-cash working capital 297 (4) 362 9
Cash flow 921 1,565 3,961 6,163
Cash provided by discontinued 9 (71) (85) (465)
operations 1
Cash flow from continuing operations 930 1,494 3,876 5,698
Cash flow per share 0.91 1.54 3.90 6.06
Cash flow from continuing 0.92 1.47 3.82 5.59
operations per share
1. Comparatives restated for operations classified as discontinued during 2009.
Earnings from continuing operations are calculated by adjusting the Company's net income per the financial statements, for certain items of a non-operational nature, on an after tax basis. The Company uses this information to evaluate performance of core operational activities on a comparable basis between periods. Earnings from continuing operations per share are earnings from continuing operations divided by the average number of common shares outstanding during the period. A reconciliation of net income to earnings from continuing operations follows.
Earnings from Continuing Operations December 31, 2009 C$ million, except per share amounts
Three Months ended Year ended
December 31, 2009 20086 2009 20086
Net income (loss) from (190) 1,162 (708) 3,122
continuing operations
Unrealized (gain) loss on financial 173 (805) 1,056 (877)
instruments 1 (tax adjusted)
Additional DD&A expense - 225 - 225
2 (tax adjusted)
Stock-based compensation expense 20 (26) 198 (56)
(recovery)3 (tax adjusted)
Restructuring charges (tax adjusted) 14 - 14 -
Future tax rate changes 21 - 21 -
Future tax charge (recovery) of 38 (54) 59 (84)
unrealized foreign exchange
(losses) on net foreign
denominated debt 4
Earnings from continuing operations 5 76 502 640 2,330
Per share5 0.07 0.49 0.63 2.29
1. Unrealized losses on financial instruments relate to the change in the period of the mark-to-market value of the company's held-for-trading financial instruments.
2. Additional DD&A expense relates to properties in the UK and Norway that had no proved reserves at 2008 year-end prices. The net book value of these properties was charged to DD&A expense in the fourth quarter of 2008.
3. Stock-based compensation expense relates to the mark-to-market value of the company's outstanding stock options and cash units at December 31. The company's stock-based compensation expense is based on the difference between the company's share price and its stock options or cash units exercise price.
4. Tax adjustment reflects future taxes relating to unrealized foreign exchange gains and losses associated with the impact of fluctuations in the Canadian dollar on net foreign denominated debt.
5. This is a non-GAAP measure. Refer to the section in this news release entitled Non-GAAP Measures for further explanation and details.
6. Comparatives restated for operations classified as discontinued in 2009.
Net debt is calculated by adjusting the Company's long-term debt per the financial statements for bank indebtedness, and cash and cash equivalents. The Company uses this information to assess its true debt position and eliminate the impact of timing differences.
Net Debt December 31, 2009 $ million
Year ended
December 31, 2009 2008
Long-term debt (including current portion) 3,780 3,961
Bank indebtedness 36 81
Cash and cash equivalents (1,690) (91)
Net debt 2,126 3,951
Talisman Energy Inc.
Highlights
(unaudited)
Three months ended Year ended
December 31 December 31
(C$ million) 2009 2008 2009 2008
Financial
(millions of C$ unless otherwise stated)
Cash flow (1) 921 1,565 3,961 6,163
Net income (loss) (111) 1,202 437 3,519
Capital expenditures 1,436 1,558 4,080 4,872
Per common share (C$)
Cash flow (1) 0.91 1.54 3.90 6.06
Net income (loss) (0.11) 1.18 0.43 3.46
Production
(daily average)
Oil and liquids (mbbls/d)
North America 29 41 34 40
UK 79 96 86 94
Scandinavia 38 34 34 33
Southeast Asia 43 35 41 36
Other 14 21 16 21
Total oil and liquids 203 227 211 224
Natural gas (mmcf/d)
North America 787 828 803 856
UK 13 41 19 38
Scandinavia 100 19 58 19
Southeast Asia 420 340 403 334
Total natural gas 1,320 1,228 1,283 1,247
Total mboe/d (2) 423 432 425 432
Prices (3)
Oil and liquids (C$/bbl)
North America 64.24 51.78 54.96 85.52
UK 78.78 58.10 68.36 98.35
Scandinavia 77.61 59.08 69.73 99.23
Southeast Asia 84.26 36.64 71.17 97.63
Other 100.59 53.50 74.03 102.51
Total oil and liquids 79.18 53.36 67.36 96.43
Natural gas (C$/mcf)
North America 4.86 7.23 4.70 8.66
UK 4.41 10.62 4.73 9.78
Scandinavia 4.99 8.44 5.86 7.16
Southeast Asia 7.19 6.53 6.40 9.94
Total natural gas 5.61 7.17 5.29 9.01
Total (C$/boe) (2) 55.51 48.45 49.40 76.03
(1) Cash flow and cash flow per share are non-GAAP measures.
(2) Barrels of oil equivalent (boe) is calculated at a conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel of oil.
(3) Prices are before hedging.
Includes the results from continuing and discontinued operations.
Talisman Energy Inc.
Consolidated Balance Sheets
(unaudited)
(C$ million)
December 31 (millions of C$) 2009 2008
(restated)
Assets
Current
Cash and cash equivalents 1,690 91
Accounts receivable 1,293 2,419
Inventories 144 181
Prepaid expenses 9 17
Assets of discontinued operations 18 220
3,154 2,928
Other assets 290 235
Goodwill 1,238 1,248
Property, plant and equipment 18,914 18,540
Assets of discontinued operations 22 1,324
20,464 21,347
Total assets 23,618 24,275
Liabilities
Current
Bank indebtedness 36 81
Accounts payable and accrued liabilities 2,130 1,875
Income and other taxes payable 357 468
Current portion of long-term debt 10 -
Future income taxes 68 300
Liabilities of discontinued operations - 94
2,601 2,818
Deferred credits 59 51
Asset retirement obligations 2,183 1,939
Other long-term obligations 168 173
Long-term debt 3,770 3,961
Future income taxes 3,720 4,007
Liabilities of discontinued operations 6 176
9,906 10,307
Shareholders' equity
Common shares, no par value
Authorized: unlimited
Issued and outstanding:
2009 - 1,015 million (2008 - 1,015 million) 2,374 2,372
Contributed surplus 153 84
Retained earnings 9,174 8,966
Accumulated other comprehensive loss (590) (272)
11,111 11,150
Total liabilities and shareholders' equity 23,618 24,275
Prior period balances have been restated to reflect the financial position of discontinued operations.
Talisman Energy Inc.
Consolidated Statements
of Income and Loss
(unaudited)
(C$ million)
Three months ended Year ended
December 31 December 31
2009 2008 2009 2008
(restated) (restated)
Revenue
Gross sales 2,180 2,120 7,528 11,275
Hedging loss - - - (28)
Gross sales, net 2,180 2,120 7,528 11,247
of hedging
Less royalties 381 372 1,155 2,001
Net sales 1,799 1,748 6,373 9,246
Other 26 25 115 112
Total revenue 1,825 1,773 6,488 9,358
Expenses
Operating 498 524 1,997 1,967
Transportation 64 44 222 207
General and administrative 88 97 334 294
Depreciation, depletion 677 1,186 2,674 2,890
and amortization
Dry hole 204 220 584 492
Exploration 100 158 301 429
Interest on long-term debt 49 43 192 168
Stock-based compensation 42 (36) 290 (73)
(recovery)
(Gain) 142 (1,695) 412 (1,664)
loss on held-for-trading
financial instruments
Other, net 23 (49) 48 (179)
Total expenses 1,887 492 7,054 4,531
Income (loss) from (62) 1,281 (566) 4,827
continuing
operations before taxes
Taxes
Current income tax 253 249 720 1,375
Future income tax (174) (146) (686) 154
(recovery)
Petroleum revenue tax 49 16 108 176
128 119 142 1,705
Net income (loss) from (190) 1,162 (708) 3,122
continuing operations
Net income from 79 40 1,145 397
discontinued
operations
Net income (loss) (111) 1,202 437 3,519
Per common share (C$):
Net income (loss) from (0.19) 1.14 (0.70) 3.07
continuing operations
Diluted net income (0.19) 1.13 (0.70) 3.02
(loss) from
continuing operations
Net income from 0.07 0.04 1.12 0.39
discontinued
operations
Diluted net income 0.07 0.04 1.12 0.38
from discontinued
operations
Net income (loss) (0.11) 1.18 0.43 3.46
Diluted net income (loss) (0.11) 1.17 0.43 3.40
Average number of 1,015 1,015 1,015 1,017
common shares
outstanding (millions)
Diluted number of 1,015 1,025 1,015 1,034
common shares
outstanding (millions)
Prior period balances have
been restated to reflect
the results of
discontinued
operations.
Talisman Energy Inc.
Consolidated Statements
of Cash Flows
(unaudited)
(C$ million)
Three months ended Year ended
December 31 December 31
2009 2008 2009 2008
(restated) (restated)
Operating
Net income (loss) from (190) 1,162 (708) 3,122
continuing operations
Items not involving cash 1,020 174 4,283 2,147
Exploration 100 158 301 429
930 1,494 3,876 5,698
Changes in non-cash (297) 4 (362) (9)
working capital
Cash provided by continuing 633 1,498 3,514 5,689
operations
Cash provided by (used in) (9) 71 85 465
discontinued operations
Cash provided by operating 624 1,569 3,599 6,154
activities
Investing
Capital expenditures
Exploration, development (1,436) (1,558) (4,080) (4,872)
and other
Property acquisitions (32) 3 (310) (436)
Proceeds of resource 96 8 200 47
property
dispositions
Changes in non-cash 139 231 (18) 244
working capital
Discontinued operations, net 492 (78) 2,341 43
of capital expenditures
Cash used in investing (741) (1,394) (1,867) (4,974)
activities
Financing
Long-term debt repaid - (739) (970) (3,869)
Long-term debt issued 12 551 1,261 2,425
Common shares purchased 1 - 1 1
Acquisition of common shares - - - (68)
for performance share plan
Common share dividends (114) (102) (229) (204)
Deferred credits and other (24) (4) (10) 8
Changes in non-cash 3 (10) 4 (14)
working capital
Cash provided by (used in) (122) (304) 57 (1,721)
financing activities
Effect of translation (41) 8 (133) 32
on foreign currency
cash and cash equivalents
Net increase (decrease) in (280) (121) 1,656 (509)
cash and cash equivalents
Cash and cash equivalents 1,948 133 12 521
net of bank
indebtedness, beginning
of period
Cash and cash equivalents 1,668 12 1,668 12
net of
bank indebtedness,
end of period
Cash and cash equivalents 1,690 91 1,690 91
Cash and cash equivalents 14 2 14 2
reclassified
to discontinued operations
Bank indebtedness (36) (81) (36) (81)
Cash and cash equivalents 1,668 12 1,668 12
net of
bank indebtedness,
end of period
Prior period balances have
been restated to reflect
the cash flows of
discontinued
operations.
Supplemental financial information
The following supplemental financial information has been prepared to assist readers of the unaudited consolidated financial information as at and for the three month period and year ended December 31, 2009. This financial information does not constitute interim financial statements as defined by Generally Accepted Accounting Principles in that certain statements and disclosures normally required to be included in interim financial statements and the notes thereto have not been provided. This unaudited consolidated financial information should be read in conjunction with the audited annual Consolidated Financial Statements as at and for the year ended December 31, 2008 and the most recently completed unaudited interim Consolidated Financial Statements as at and for the three and nine month periods ended September 30, 2009.
Commodity derivatives
Commodity price derivative contracts
The Company had the following commodity price derivative contracts outstanding at December 31, 2009:
$ million
Fixed price swaps Term mcf/d C$/mcf Fair value
ICE index Jan-Mar 2010 20,638 7.28 3
ICE index Apr-Sep 2010 20,638 5.98 -
ICE index Oct-Dec 2010 17,824 7.03 (2)
ICE index Jan-Mar 2011 17,824 7.03 (4)
ICE index Apr-Jun 2011 16,886 6.41 (3)
(6)
Floor/ceiling
Two-way collars Term bbls/d US$/bbl Fair value
Dated Brent oil index Jan-Dec 2010 28,000 52.57/80.14 (84)
Dated Brent oil index Jan-Dec 2010 25,000 71.72/90.00 (1)
WTI Jan-Dec 2010 22,000 50.20/60.87 (187)
(272)
Floor/ceiling
Two-way collars Term mcf/d C$/mcf Fair value
AECO index Jan-Jun 2010 94,820 5.82/7.17 8
AECO index Jan-Dec 2010 47,410 5.78/7.39 6
14
Floor/ceiling
Two-way collars Term mcf/d US$/mcf Fair value
NYMEX index Jul-Dec 2010 95,000 5.90/7.03 (1)
Physical commodity contracts
The Company had the following physical commodity contracts outstanding at December 31, 2009:
Fixed price swaps Term mcf/d C$/mcf
AECO natural gas swaps Jan-Dec 2010 14,223 6.33
AECO natural gas collars Jan-Dec 2010 175,417 6.33/7.55
AECO natural gas swaps Jan 2010-Dec 2011 3,671 3.10
Supplemental cash flow information
Items not involving cash are as follows:
Three months ended Year ended
December 31 December 31
(C$ million) 2009 2008 2009 2008
Depreciation, depletion 677 1,186 2,674 2,890
& amortization
Dry hole 204 220 584 492
Net gain on asset disposals (22) (43) (37) (109)
Stock-based compensation 16 (40) 213 (284)
expense (recovery)
Future taxes and deferred (157) (151) (645) 247
PRT (recovery)
Unrealized (gains) 238 (1,072) 1,390 (1,222)
losses on held for
trading financial instruments
Financial instruments (5) (8) 11 46
contract premium
Other 69 82 93 87
1,020 174 4,283 2,147
North America1 UK Scandinavia
(C$ million) 2009 2008 2007 2009 2008 2007 2009 2008 2007
Revenue
Gross sales 1,911 3,636 2,574 2,188 3,458 2,606 986 1,192 827
Hedging gain - - 110 - (28) (6) - - -
(loss)
Royalties 246 631 462 5 13 4 - - -
Net sales 1,665 3,005 2,222 2,183 3,417 2,596 986 1,192 827
Other 93 84 76 19 25 18 3 3 22
Total revenue 1,758 3,089 2,298 2,202 3,442 2,614 989 1,195 849
Segmented
expenses
Operating 539 534 446 878 942 872 285 276 279
Transportation 59 68 65 46 49 51 54 35 34
DD&A 1,062 1,052 967 781 1,144 605 406 416 264
Dry hole 179 269 359 30 93 104 69 90 83
Exploration 84 165 148 18 54 40 22 50 34
Other (19) (86) (48) 72 23 25 (5) 15 (9)
Total segmented 1,904 2,002 1,937 1,825 2,305 1,697 831 882 685
expenses
Segmented income (146) 1,087 361 377 1,137 917 158 313 164
(loss)
before taxes
Non-segmented
expenses
General
and
administrative
Interest on
long-term
debt
Stock-based
compensation
Currency
translation
(Gain)
loss
on
held-for-trading
financial
instruments
Total
non-segmented
expenses
Income (loss)
from
continuing
operations
before
taxes
Capital
expenditure
Exploration 1,312 1,427 849 149 188 246 157 165 148
Development 492 847 764 531 545 959 528 660 436
Midstream 26 41 80 - - - - - -
Exploration and 1,830 2,315 1,693 680 733 1,205 685 825 584
development
Property
acquisitions
Proceeds
on dispositions
Other
non-segmented
Net
capital
expenditures4
Property, plant 8,638 8,259 7,023 4,549 4,738 5,683 2,040 1,745 1,536
and equipment
Goodwill 211 211 213 289 306 335 628 602 639
Other 634 833 984 386 253 301 226 154 172
Discontinued - 996 1,012 - 165 161 - 93 301
operations
Segmented assets 9,483 10,299 9,232 5,224 5,462 6,480 2,894 2,594 2,648
Non segmented
assets
Total assets
1. North America 2009 2008 2007
Canada 1,637 2,862 2,088
US 121 227 210
Total revenue 1,758 3,089 2,298
Canada 7,476 7,458 6,633
US 1,162 801 390
Property, plant and equipment 8,638 8,259 7,023
4 Excluding corporate acquisitions US
Southeast Asia2 Other3 Total
(C$ million) 2009 2008 2007 2009 2008 2007 2009 2008 2007
Revenue
Gross sales 1,995 2,479 2,096 448 510 398 7,528 11,275 8,501
Hedging gain - - - - - - - (28) 104
(loss)
Royalties 675 1,066 843 229 291 178 1,155 2,001 1,487
Net sales 1,320 1,413 1,253 219 219 220 6,373 9,246 7,118
Other - - 2 - - - 115 112 118
Total revenue 1,320 1,413 1,255 219 219 220 6,488 9,358 7,236
Segmented
expenses
Operating 255 195 169 40 20 26 1,997 1,967 1,792
Transportation 55 48 47 8 7 7 222 207 204
DD&A 382 254 248 43 24 23 2,674 2,890 2,107
Dry hole 253 13 48 53 27 1 584 492 595
Exploration 75 84 22 102 76 70 301 429 314
Other 9 29 6 7 5 9 64 (14) (17)
Total segmented 1,029 623 540 253 159 136 5,842 5,971 4,995
expenses
Segmented income 291 790 715 (34) 60 84 646 3,387 2,241
(loss)
before taxes
Non-segmented
expenses
General 334 294 223
and
administrative
Interest on 192 168 207
long-term
debt
Stock-based 290 (73) (15)
compensation
Currency (16) (165) 53
translation
(Gain) 412 (1,664) 25
loss
on
held-for-trading
financial
instruments
Total 1,212 (1,440) 493
non-segmented
expenses
Income (loss) (566) 4,827 1,748
from
continuing
operations
before
taxes
Capital
expenditure
Exploration 233 318 172 217 149 144 2,068 2,247 1,559
Development 444 459 340 46 8 24 2,041 2,519 2,523
Midstream - - - - - - 26 41 80
Exploration and 677 777 512 263 157 168 4,135 4,807 4,162
development
Property 438 452 317
acquisitions
Proceeds (321) (100) (45)
on dispositions
Other 47 64 41
non-segmented
Net 4,299 5,223 4,475
capital
expenditures4
Property, plant 2,864 2,984 2,030 823 814 227 18,914 18,540 16,499
and equipment
Goodwill 110 129 104 - - - 1,238 1,248 1,291
Other 427 304 293 156 128 39 1,829 1,672 1,789
Discontinued - - - 40 290 284 40 1,544 1,758
operations
Segmented assets 3,401 3,417 2,427 1,019 1,232 550 22,021 23,004 21,337
Non segmented 1,597 1,271 83
assets
Total assets 23,618 24,275 21,420
2. Southeast Asia 2009 2008 2007
Indonesia 693 863 591
Malaysia 400 424 445
Vietnam 101 33 56
Australia 126 93 163
Total revenue 1,320 1,413 1,255
Indonesia 906 990 820
Malaysia 1,171 1,291 899
Vietnam 241 456 147
Papua New Guinea 337 - -
Australia 209 247 164
Property, plant and equipment 2,864 2,984 2,030
3. Other
Algeria 219 219 220
Total revenue 219 219 220
Algeria 193 221 193
Other 630 593 34
Property, plant and equipment 823 814 227
4 Excluding corporate acquisitions
Continuity of Gross
Proved Reserves
United Other
Canada (1) States UK Scandinavia Indonesia Southeast Asia Other Total
Oil and liquids(mmbbls)
Total proved
Proved reserves at 166.6 - 380.8 61.9 36.0 62.3 58.9 766.5
December 31, 2006
Discoveries, additions 7.2 - 6.4 11.2 2.2 0.5 1.8 29.3
and extensions
Purchase of reserves - - - - 1.1 - - 1.1
Sale of reserves (13.4) - (4.6) - - - - (18.0)
Net revisions and transfers 8.2 - 41.8 5.4 0.5 2.7 (0.4) 58.2
2007 Production (15.8) - (37.2) (11.2) (4.1) (12.0) (7.5) (87.8)
Proved reserves at 152.8 - 387.2 67.3 35.7 53.5 52.8 749.3
December 31, 2007
Discoveries, additions 13.7 - 15.0 8.3 0.4 0.2 (0.7) 36.9
and extensions
Purchase of reserves 0.3 - - - - - - 0.3
Sale of reserves (0.3) - (17.5) (1.7) - - - (19.5)
Net revisions and transfers 2.6 - (133.7) (5.3) 0.6 (5.6) 0.6 (140.8)
2008 Production (14.8) - (34.3) (12.0) (4.3) (8.7) (7.6) (81.7)
Proved reserves at 154.3 - 216.7 56.6 32.4 39.4 45.1 544.5
December 31, 2008
Discoveries, additions 4.8 - 5.2 1.1 (1.7) 7.4 12.2 29.0
and extensions
Purchase of reserves 0.2 - - - 1.0 - - 1.2
Sale of reserves (45.7) - (0.2) (4.0) - - (3.8) (53.7)
Net revisions and transfers - - 77.0 14.5 1.1 3.8 (8.6) 87.8
2009 Production (12.6) - (31.2) (12.3) (4.2) (10.7) (5.9) (76.9)
Proved reserves at 101.0 - 267.5 55.9 28.6 39.9 39.0 531.9
December 31, 2009
Proved developed
December 31, 2006 156.4 - 255.7 25.7 30.4 39.8 43.3 551.3
December 31, 2007 146.2 - 344.5 25.6 28.2 31.3 48.2 624.0
December 31, 2008 143.4 - 173.3 24.8 26.0 24.9 35.2 427.6
December 31, 2009 92.6 - 197.1 26.1 23.2 31.2 23.7 393.9
Natural gas(bcf)
Total proved
Proved reserves at 2,661.3 143.8 182.8 76.3 1,702.5 406.3 229.9 5,402.9
December 31, 2006
Discoveries, additions 336.5 20.3 4.3 9.8 118.7 (3.8) (10.1) 475.7
and extensions
Purchase of reserves 4.6 - - - 247.2 - - 251.8
Sale of reserves (154.5) - (56.8) - - - - (211.3)
Net revisions and transfers 6.2 (6.4) (4.8) (2.1) (3.2) 6.1 4.4 0.2
2007 Production (288.4) (31.2) (25.3) (5.1) (83.3) (21.6) (0.2) (455.1)
Proved reserves at 2,565.7 126.5 100.2 78.9 1,981.9 387.0 224.0 5,464.2
December 31, 2007
Discoveries, additions 308.2 33.9 12.4 12.1 1.3 27.0 0.4 395.3
and extensions
Purchase of reserves 15.3 2.8 - - - - - 18.1
Sale of reserves (65.3) - - - - - - (65.3)
Net revisions and transfers (30.3) 1.4 (3.2) 17.8 - (2.5) (0.8) (17.6)
2008 Production (286.6) (26.7) (13.8) (6.9) (97.2) (24.9) (0.2) (456.3)
Proved reserves at 2,507.0 137.9 95.6 101.9 1,886.0 386.6 223.4 5,338.4
December 31, 2008
Discoveries, additions 201.2 544.5 - (0.5) 88.6 27.9 - 861.7
and extensions
Purchase of reserves 15.9 - - - 8.7 - - 24.6
Sale of reserves (137.6) (1.5) (67.0) - - - (220.5) (426.6)
Net revisions and transfers (75.3) 0.1 2.9 12.7 14.8 (11.1) (1.0) (56.9)
2009 Production (262.7) (30.3) (7.0) (21.1) (120.6) (26.7) (0.1) (468.5)
Proved reserves at 2,248.5 650.7 24.5 93.0 1,877.5 376.7 1.8 5,272.7
December 31, 2009
Proved developed
December 31, 2006 2,162.5 132.5 126.4 8.6 1,255.9 51.9 0.5 3,738.3
December 31, 2007 2,125.6 111.4 86.7 7.0 1,197.6 58.2 1.1 3,587.6
December 31, 2008 2,066.8 117.9 65.5 99.0 1,348.9 199.0 1.2 3,898.3
December 31, 2009 1,840.9 197.9 22.4 91.2 1,231.6 320.8 0.8 3,705.6
Notes:
1 Canadian gross proved reserves exclude synthetic crude oil
reserves: 2006 - 38.9 mmbbls; 2007 - 0 mmbbls (asset sold)
Continuity of Net
Proved Reserves
Other
United Southeast
Canada (1) States UK Scandinavia Indonesia Asia Other Total
Oil and liquids(mmbbls)
Total proved
Proved reserves at 138.3 - 377.8 61.8 14.3 39.6 33.4 665.2
December 31, 2006
Discoveries, additions 5.9 - 6.4 11.2 0.7 0.2 1.1 25.5
and extensions
Purchase of reserves - - - - 1.0 - - 1.0
Sale of reserves (9.8) - (4.1) - - - - (13.9)
Net revisions and transfers 2.0 - 42.1 5.3 (0.6) (2.8) (1.8) 44.2
2007 Production (12.5) - (36.9) (11.1) (1.8) (6.9) (5.1) (74.3)
Proved reserves at 123.9 - 385.3 67.2 13.6 30.1 27.6 647.7
December 31, 2007
Discoveries, additions 12.1 - 15.0 8.3 - (0.3) (0.3) 34.8
and extensions
Purchase of reserves 0.3 - - - - - - 0.3
Sale of reserves (0.3) - (17.5) (1.6) - - - (19.4)
Net revisions and transfers 7.4 - (133.2) (5.3) 4.2 2.0 3.1 (121.8)
2008 Production (11.9) - (34.2) (12.0) (1.7) (4.7) (4.1) (68.6)
Proved reserves at 131.5 - 215.4 56.6 16.1 27.1 26.3 473.0
December 31, 2008
Discoveries, additions 4.0 - 5.2 1.1 (0.5) 5.3 6.5 21.6
and extensions
Purchase of reserves 0.1 - - - 0.7 - - 0.8
Sale of reserves (39.0) - (0.2) (4.0) - - (3.7) (46.9)
Net revisions and transfers 2.7 - 76.8 14.5 (1.8) 3.8 (4.7) 91.3
2009 Production (9.9) - (31.1) (12.3) (1.8) (7.6) (3.4) (66.1)
Proved reserves at 89.4 - 266.1 55.9 12.7 28.6 21.0 473.7
December 31, 2009
Proved developed
December 31, 2006 130.1 - 252.9 25.6 12.2 24.7 25.8 471.3
December 31, 2007 118.9 - 342.6 25.6 10.7 18.9 25.4 542.1
December 31, 2008 122.0 - 172.0 24.8 13.5 17.7 20.2 370.2
December 31, 2009 82.1 - 196.0 26.1 11.0 21.2 13.0 349.4
Natural gas(bcf)
Total proved
Proved reserves at 2,153.8 123.8 178.1 76.3 1,174.2 276.5 229.3 4,212.0
December 31, 2006
Discoveries, additions 254.5 17.7 4.3 9.8 78.3 (1.6) (10.2) 352.8
and extensions
Purchase of reserves 3.3 - - - 192.2 - - 195.5
Sale of reserves (117.9) - (53.0) - - - - (170.9)
Net revisions and transfers 29.8 (6.0) (5.3) (2.1) (28.9) (13.1) 4.3 (21.3)
2007 Production (236.4) (26.5) (23.9) (5.1) (56.8) (16.3) (0.1) (365.1)
Proved reserves at 2,087.1 109.0 100.2 78.9 1,359.0 245.5 223.3 4,203.0
December 31, 2007
Discoveries, additions 249.7 29.4 12.4 12.1 (30.3) 20.2 0.4 293.9
and extensions
Purchase of reserves 11.9 2.4 - - - - - 14.3
Sale of reserves (55.2) - - - - - - (55.2)
Net revisions and transfers 113.3 1.3 (3.2) 17.8 143.0 42.8 (0.7) 314.3
2008 Production (237.6) (22.9) (13.8) (6.9) (64.0) (18.8) (0.2) (364.2)
Proved reserves at 2,169.2 119.2 95.6 101.9 1,407.7 289.7 222.8 4,406.1
December 31, 2008
Discoveries, additions 185.6 474.6 - (0.5) 62.8 25.3 - 747.8
and extensions
Purchase of reserves 14.2 - - - 7.5 - - 21.7
Sale of reserves (115.8) (1.4) (67.0) - - (220.0) (404.2)
Net revisions and transfers 28.2 - 2.9 12.7 (19.5) (33.3) (1.0) (10.0)
2009 Production (238.4) (26.2) (7.0) (21.1) (84.4) (20.3) (0.1) (397.5)
Proved reserves at 2,043.0 566.2 24.5 93.0 1,374.1 261.4 1.7 4,363.9
December 31, 2009
Proved developed
December 31, 2006 1,747.1 113.8 123.2 8.6 856.8 38.7 0.5 2,888.7
December 31, 2007 1,725.0 95.7 86.7 7.0 811.1 44.4 1.0 2,770.9
December 31, 2008 1,785.8 101.8 65.5 99.0 1,022.2 149.0 1.2 3,224.5
December 31, 2009 1,663.5 171.1 22.4 91.2 915.2 225.5 0.8 3,089.7
Notes:
1 Canadian net proved reserves exclude synthetic crude
oil reserves: 2006 - 32 mmbbls; 2007 - 0 (asset sold)
Reserves Estimates
Summary of Oil and Gas Reserves as of Fiscal Year End Based on Average Fiscal Year Prices
The following table sets forth Talisman's estimates of its proved developed, proved undeveloped, total proved, probable developed, probable undeveloped and total probable reserves as at December 31, 2009. The reserves estimates included in this table were prepared using the standards of the US Securities and Exchange Commission ("SEC"), which requires that proved reserves be estimated using existing economic conditions.
Effective January 1, 2010, the SEC amended its oil and gas reporting requirements. Under the amended requirements, the price used for calculating reserves has been changed from a year-end single day price to an average price during the 12-month period for the most recent fiscal year, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period unless the prices are defined by contractual obligations (excluding escalations based on future conditions). The estimates in the following table have been prepared on that basis.
Proved Proved Total Probable Probable Total
Developed1,2 Undeveloped1,3 Proved1 Developed4,5 Undeveloped4,6 Probable4
Gross7 Net8 Gross7 Net8 Gross7 Net8 Gross7 Net8 Gross7 Net8 Gross7 Net8
Oil
and
Liquids
(mmbbls)
North
America
Canada 92.6 82.1 8.4 7.3 101.0 89.4 20.3 17.4 8.3 6.6 28.6 24.0
US - - - - - - - - - - - -
UK
UK 197.1 196.0 70.4 70.1 267.5 266.1 59.4 59.1 112.4 112.4 171.8 171.5
Scandinavia
Norway 26.1 26.1 29.8 29.8 55.9 55.9 22.7 22.7 42.3 42.3 65.0 65.0
Southeast
Asia
Indonesia9 23.2 11.0 5.4 1.7 28.6 12.7 0.5 0.2 11.6 5.1 12.1 5.3
Malaysia 23.7 14.0 3.6 2.5 27.3 16.5 23.8 11.9 9.5 3.9 33.3 15.8
Australia 6.0 5.9 5.1 4.9 11.1 10.8 2.9 2.8 4.3 4.1 7.2 6.9
Vietnam 1.5 1.3 - - 1.5 1.3 0.3 0.3 28.5 23.2 28.8 23.5
Other
Algeria 23.2 12.6 15.1 7.9 38.3 20.5 6.2 3.2 6.1 3.6 12.3 6.8
Tunisia 0.5 0.4 0.2 0.1 0.7 0.5 0.2 0.1 - - 0.2 0.1
Total 393.9 349.4 138.0 124.3 531.9 473.7 136.3 117.7 223.0 201.2 359.3 318.9
Natural
Gas(bcf)
North
America
Canada 1840.9 1663.5 407.6 379.5 2248.5 2043.0 603.7 546.4 648.2 593.9 1251.9 1140.3
US 197.9 171.1 452.8 395.1 650.7 566.2 7.7 6.7 524.5 453.6 532.2 460.3
UK
UK 22.4 22.4 2.1 2.1 24.5 24.5 20.2 20.2 168.8 168.8 189.0 189.0
Scandinavia
Norway 91.2 91.2 1.8 1.8 93.0 93.0 57.0 57.0 8.0 8.0 65.0 65.0
Southeast
Asia
Indonesia9 1231.6 915.2 645.9 458.9 1877.5 1374.1 3.7 2.3 714.3 500.0 718.0 502.3
Malaysia 320.8 225.5 55.9 35.9 376.7 261.4 154.5 84.1 97.8 63.9 252.3 148.0
Australia - - - - - - - - - - - -
Vietnam - - - - - - - - 23.1 23.1 23.1 23.1
Other
Algeria - - - - - - - - - - - -
Tunisia 0.8 0.8 1.0 0.9 1.8 1.7 0.7 0.6 0.1 0.1 0.8 0.7
Total 3705.6 3089.7 1567.1 1274.2 5272.7 4363.9 847.5 717.3 2184.8 1811.4 3032.3 2528.7
Notes:
1. "Proved" reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.
2. "Proved Developed" reserves are those reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional oil and gas expected to be obtained through installed extraction equipment and infrastructure operational at the time of the reserves estimate are included as proved developed reserves.
3. "Proved Undeveloped" reserves are those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which a relatively major expenditure is required for recompletion. Inclusion of reserves on undrilled acreage is limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
4. "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Probable reserves can be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Includes reserves assigned to areas of a reservoir adjacent to proved reserves where data control or interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.
5. "Probable Developed" reserves are those reserves that are less certain to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional oil and gas expected to be obtained through installed extraction equipment and infrastructure operational at the time of the reserves estimate are included as proved developed reserves.
6. "Probable Undeveloped" reserves are those reserves that are less certain to be recovered from new wells on undrilled acreage, or from existing wells for which a relatively major expenditure is required for recompletion.
7. "Gross" reserves refer to the sum of (i) working interest reserves before deduction of royalty burdens payable, and (ii) royalty interest reserves. The Canadian Oil and Gas Evaluation Handbook ("COGEH") refers to this sum of reserves as "Company interest reserves". Royalty interest reserves for Canada were approximately 1.3 mmboe (proved) and 0.3 mmboe (probable) as at December 31, 2009. The inclusion of royalty interest volumes in gross reserves does not conform to COGEH standards applicable under NI 51-101.
8. "Net" reserves are the remaining reserves of Talisman, after deduction of estimated royalty burdens and including royalty interests in the amount set out in note 7 above.
9. Interests of various governments, other than working interests or income taxes, are accounted for as royalties. Royalties are reflected in "net" reserves using effective rates over the life of the contract.
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