Exhibit 99.2
INTERIM MANAGEMENT’S DISCUSSION AND ANALYSIS
FOR THE PERIOD ENDED JUNE 30, 2014
Management’s Discussion and Analysis (MD&A)
(July 29, 2014)
General
This interim MD&A should be read in conjunction with the unaudited interim condensed Consolidated Financial Statements of Talisman Energy Inc. (‘Talisman’ or ‘the Company’) as at and for the three and six month periods ended June 30, 2014 and 2013, and the 2013 MD&A and audited annual Consolidated Financial Statements of the Company. The Company’s interim condensed Consolidated Financial Statements have been prepared in accordance with International Accounting Standard (IAS) 34, Interim Financial Reporting within International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
Talisman’s financial statements are prepared on a consolidated basis and include the accounts of Talisman and its subsidiaries. Substantially all of Talisman’s activities are conducted jointly with others, and the condensed Consolidated Financial Statements reflect only the Company’s proportionate interest in such activities, with the exception of the Company’s investments in Talisman Sinopec Energy UK Limited (TSEUK) and Equion Energía Limited (Equion) which are accounted for using the equity method. Talisman’s investment in the Ocensa pipeline was accounted for using the equity method of accounting until December 19, 2013 when the Company sold its 12.152% equity interest.
All comparisons are between the three month periods ended June 30, 2014 and 2013, unless stated otherwise. All amounts presented are in US$, except where otherwise indicated. Abbreviations used in this MD&A are listed in the section “Abbreviations and Definitions”. Unless otherwise indicated, amounts only reflect results from consolidated subsidiaries. Additional information relating to the Company, including its Annual Information Form (AIF), can be found on the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com.
1
SECOND QUARTER 2014 PERFORMANCE HIGHLIGHTS
· | Production from ongoing operations was 364 mboe/d, up 12% compared to the second quarter 2013. |
· | Liquids production is up 15% year-over-year to 145 mbbls/d, with North American liquids up 36% to 45 mbbls/d over the same period. |
FINANCIAL AND OPERATING HIGHLIGHTS
($ millions, unless otherwise stated) | Six Months Ended June 30, | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | |||||||||||||||||||||||||||||||
2014 | 2013 | 2014 | 2014 | 2013 | 2013 | 2013 | 2013 | 2012 | 2012 | |||||||||||||||||||||||||||||||
Total revenue and other income1 | 2,583 | 2,313 | 1,242 | 1,341 | 929 | 1,244 | 1,190 | 1,123 | 1,663 | 1,647 | ||||||||||||||||||||||||||||||
Net income (loss) | 254 | (116 | ) | (237 | ) | 491 | (1,005 | ) | (54 | ) | 97 | (213 | ) | 376 | (731 | ) | ||||||||||||||||||||||||
Per common share ($) | ||||||||||||||||||||||||||||||||||||||||
Net income (loss)2 | 0.24 | (0.12 | ) | (0.23 | ) | 0.47 | (0.98 | ) | (0.05 | ) | 0.09 | (0.21 | ) | 0.37 | (0.71 | ) | ||||||||||||||||||||||||
Diluted net income (loss)3 | 0.19 | (0.14 | ) | (0.24 | ) | 0.43 | (0.98 | ) | (0.08 | ) | 0.06 | (0.21 | ) | 0.31 | (0.71 | ) | ||||||||||||||||||||||||
Production4 (Daily Average - Gross) | ||||||||||||||||||||||||||||||||||||||||
Oil and liquids (mbbls/d) | 144 | 127 | 145 | 142 | 137 | 134 | 126 | 129 | 143 | 159 | ||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 1,415 | 1,438 | 1,380 | 1,452 | 1,505 | 1,423 | 1,414 | 1,461 | 1,498 | 1,533 | ||||||||||||||||||||||||||||||
Total mboe/d (6mcf = 1boe) | 380 | 367 | 375 | 384 | 387 | 371 | 361 | 372 | 392 | 415 |
1. | 2012 restated to reflect the change to equity accounting of Equion. Adjustments relating to TSEUK are effective for the period of December 17, 2012 to December 31, 2012 as the TSEUK joint venture was formed on December 17, 2012. |
2. | Net income (loss) per share includes an adjustment to the numerator for after-tax cumulative preferred share dividends. |
3. | Diluted net income (loss) per share computed under IFRS includes an adjustment to the numerator for the change in the fair value of stock options and after-tax cumulative preferred share dividends. |
4. | Includes the Company’s proportionate interest in production from joint ventures. |
During the second quarter of 2014, the Company had a net loss of $237 million compared to net income of $97 million in the same quarter in 2013 as a result of a loss on held-for-trading financial instruments compared to a gain in 2013, gains on disposals recorded in 2013 and higher impairments in 2014. These were partially offset by higher production and lower income taxes.
Higher production volumes from ongoing operations in the second quarter of 2014 were primarily driven by increased volumes in Colombia from the Akacias field, North America and the North Sea.
2
DAILY AVERAGE PRODUCTION
Three months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Oil and liquids from Consolidated Subsidiaries (mbbls/d) | ||||||||||||||||
North America | 45 | 33 | 35 | 25 | ||||||||||||
Southeast Asia | 45 | 43 | 28 | 23 | ||||||||||||
North Sea | 11 | 13 | 11 | 13 | ||||||||||||
Other | 16 | 10 | 9 | 5 | ||||||||||||
117 | 99 | 83 | 66 | |||||||||||||
Oil and liquids from Joint Ventures (mbbls/d) | ||||||||||||||||
TSEUK | 19 | 17 | 19 | 17 | ||||||||||||
Equion | 9 | 10 | 7 | 9 | ||||||||||||
28 | 27 | 26 | 26 | |||||||||||||
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d) | 145 | 126 | 109 | 92 | ||||||||||||
Natural gas from Consolidated Subsidiaries (mmcf/d) | ||||||||||||||||
North America | 795 | 846 | 682 | 733 | ||||||||||||
Southeast Asia | 515 | 519 | 351 | 358 | ||||||||||||
North Sea | 20 | 4 | 20 | 4 | ||||||||||||
Other | - | - | - | - | ||||||||||||
1,330 | 1,369 | 1,053 | 1,095 | |||||||||||||
Natural gas from Joint Ventures (mmcf/d) | ||||||||||||||||
TSEUK | 2 | 2 | 2 | 2 | ||||||||||||
Equion | 48 | 43 | 37 | 34 | ||||||||||||
50 | 45 | 39 | 36 | |||||||||||||
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d) | 1,380 | 1,414 | 1,092 | 1,131 | ||||||||||||
Total Daily Production from Consolidated Subsidiaries (mboe/d) | ||||||||||||||||
North America | 177 | 174 | 149 | 147 | ||||||||||||
Southeast Asia | 131 | 130 | 87 | 83 | ||||||||||||
North Sea | 15 | 13 | 15 | 13 | ||||||||||||
Other | 16 | 10 | 8 | 5 | ||||||||||||
339 | 327 | 259 | 248 | |||||||||||||
Total Daily Production from Joint Ventures (mboe/d) | ||||||||||||||||
TSEUK | 19 | 17 | 19 | 17 | ||||||||||||
Equion | 17 | 17 | 13 | 15 | ||||||||||||
36 | 34 | 32 | 32 | |||||||||||||
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d) | 375 | 361 | 291 | 280 | ||||||||||||
Less production from assets sold or held for sale (mboe/d) | ||||||||||||||||
North America | 8 | 32 | 6 | 30 | ||||||||||||
Southeast Asia | 3 | 4 | 2 | 3 | ||||||||||||
11 | 36 | 8 | 33 | |||||||||||||
Total production from ongoing operations (mboe/d) | 364 | 325 | 283 | 247 |
3
Six months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Oil and liquids from Consolidated Subsidiaries (mbbls/d) | ||||||||||||||||
North America | 43 | 31 | 34 | 24 | ||||||||||||
Southeast Asia | 45 | 42 | 28 | 21 | ||||||||||||
North Sea | 13 | 15 | 13 | 15 | ||||||||||||
Other | 15 | 11 | 8 | 5 | ||||||||||||
116 | 99 | 83 | 65 | |||||||||||||
Oil and liquids from Joint Ventures (mbbls/d) | ||||||||||||||||
TSEUK | 19 | 18 | 19 | 18 | ||||||||||||
Equion | 9 | 10 | 7 | 9 | ||||||||||||
28 | 28 | 26 | 27 | |||||||||||||
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d) | 144 | 127 | 109 | 92 | ||||||||||||
Natural gas from Consolidated Subsidiaries (mmcf/d) | ||||||||||||||||
North America | 831 | 861 | 721 | 753 | ||||||||||||
Southeast Asia | 518 | 525 | 351 | 352 | ||||||||||||
North Sea | 17 | 9 | 17 | 9 | ||||||||||||
Other | - | - | - | - | ||||||||||||
1,366 | 1,395 | 1,089 | 1,114 | |||||||||||||
Natural gas from Joint Ventures (mmcf/d) | ||||||||||||||||
TSEUK | 2 | 2 | 2 | 2 | ||||||||||||
Equion | 47 | 41 | 38 | 33 | ||||||||||||
49 | 43 | 40 | 35 | |||||||||||||
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d) | 1,415 | 1,438 | 1,129 | 1,149 | ||||||||||||
Total Daily Production from Consolidated Subsidiaries (mboe/d) | ||||||||||||||||
North America | 182 | 174 | 155 | 150 | ||||||||||||
Southeast Asia | 131 | 130 | 87 | 80 | ||||||||||||
North Sea | 16 | 16 | 16 | 16 | ||||||||||||
Other | 15 | 11 | 8 | 5 | ||||||||||||
344 | 331 | 266 | 251 | |||||||||||||
Total Daily Production from Joint Ventures (mboe/d) | ||||||||||||||||
TSEUK | 19 | 19 | 18 | 19 | ||||||||||||
Equion | 17 | 17 | 13 | 14 | ||||||||||||
36 | 36 | 31 | 33 | |||||||||||||
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d) | 380 | 367 | 297 | 284 | ||||||||||||
Less production from assets sold (mboe/d) | ||||||||||||||||
North America | 18 | 31 | 16 | 31 | ||||||||||||
Southeast Asia | 3 | 6 | 2 | 3 | ||||||||||||
21 | 37 | 18 | 34 | |||||||||||||
Total production from ongoing operations (mboe/d) | 359 | 330 | 279 | 250 |
Production represents gross production before royalties, unless noted otherwise. Production identified as net is production after deducting royalties.
Production from ongoing operations was 364 mboe/d, an increase of 12% compared to 2013 due principally to increased liquids production in North America.
In North America, production from ongoing operations increased by 19% compared to 2013. Capital investment in North America continues to be prioritized towards liquids-rich opportunities, resulting in oil and liquids increasing from 19% to 25% of the overall North American production mix for 2014. Oil and liquids production increased by 36% due principally to increased development activity in the Eagle Ford and the onset of new liquids production in the Edson area. Natural gas production decreased by 6% due principally to the sale of the Company’s Montney position and other non-core assets in western Canada, partially offset by increased development activity in the Marcellus and Eagle Ford.
4
In Southeast Asia, total production from ongoing operations increased by 2% compared to 2013. Total oil and liquids production increased by 5% due principally to the start-up of HST / HSD in Vietnam in May and June of 2013, partially offset by reduced production from Kitan in Australia due to natural decline and maintenance. Natural gas production decreased due principally to precautionary shutdown and subsequent reduced gas supply from the PM-3 offshore facility in Malaysia.
Production in Norway increased by 15% due principally to increased production at Varg as a result of the start-up of the Varg gas export in the first quarter of 2014 partially offset by planned maintenance and natural declines at Brage and Veslefrikk. In the TSEUK joint venture, production increased by 12% due principally to improved uptime at Bleoholm and Piper, and the restart of production at Claymore, partially offset by unplanned outages at Monarb.
In the Other segment, including the Equion joint venture, production was 33 mboe/d in 2014 compared to 27 mboe/d in 2013. Liquids production in Colombia increased principally due to additional long-term testing wells in Akacias. Algeria production increased principally due to new production at EMK which started during the second quarter of 2013.
VOLUMES PRODUCED INTO (SOLD OUT OF) INVENTORY1,2
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
North America - bbls/d³ | (571 | ) | - | (22 | ) | - | ||||||||||
Southeast Asia - bbls/d | 3,822 | (10,879 | ) | 3,375 | (1,721 | ) | ||||||||||
North Sea – bbls/d | 1,842 | (1,369 | ) | 263 | (121 | ) | ||||||||||
Other – bbls/d | (3,142 | ) | 2,878 | 259 | (453 | ) | ||||||||||
Total produced into (sold out of) inventory – bbls/d | 1,951 | (9,370 | ) | 3,875 | (2,295 | ) | ||||||||||
Total produced into (sold out of) inventory – mmbbls | 0.2 | (0.9 | ) | 0.7 | (0.4 | ) | ||||||||||
Inventory at June 30 - mmbbls | 1.9 | 1.7 | 1.9 | 1.7 |
1. | Gross before royalties. |
2. | Effective January 1, 2013, the North Sea volumes only include Norway. |
3. | Volumes exclude linefill amounts capitalized to PP&E. |
In the Company's international operations, produced oil is frequently stored in tanks until there is sufficient volume to be lifted. The Company recognizes revenue and the related expenses on crude oil production when liftings have occurred. Volumes presented in the “Daily Average Production” table represent production volumes in the period, which include oil volumes produced into inventory and exclude volumes sold out of inventory.
During the three month period ended June 30, 2014, volumes in inventory increased from 1.7 mmbbls to 1.9 mmbbls due principally to increased inventories in Malaysia, Norway and Indonesia, partially offset by decreased inventories in Algeria, Australia and North America.
5
COMPANY NETBACKS1,2
Three months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Oil and liquids ($/bbl) | ||||||||||||||||
Sales price | 93.08 | 89.51 | 93.08 | 89.51 | ||||||||||||
Royalties | 28.18 | 30.73 | - | - | ||||||||||||
Transportation | 1.58 | 1.51 | 2.26 | 2.30 | ||||||||||||
Operating costs | 22.65 | 23.79 | 32.50 | 36.23 | ||||||||||||
40.67 | 33.48 | 58.32 | 50.98 | |||||||||||||
Natural gas ($/mcf) | ||||||||||||||||
Sales price | 6.18 | 6.12 | 6.18 | 6.12 | ||||||||||||
Royalties | 1.47 | 1.45 | - | - | ||||||||||||
Transportation | 0.22 | 0.30 | 0.29 | 0.40 | ||||||||||||
Operating costs | 1.04 | 1.14 | 1.36 | 1.49 | ||||||||||||
3.45 | 3.23 | 4.53 | 4.23 | |||||||||||||
Total $/boe (6mcf=1boe) | ||||||||||||||||
Sales price | 56.47 | 52.68 | 56.47 | 52.68 | ||||||||||||
Royalties | 15.53 | 15.35 | - | - | ||||||||||||
Transportation | 1.42 | 1.72 | 1.95 | 2.43 | ||||||||||||
Operating costs | 11.92 | 11.96 | 16.11 | 16.35 | ||||||||||||
27.60 | 23.65 | 38.41 | 33.90 |
1. | Netbacks do not include pipeline operations. |
2. | Amounts shown only represent netbacks from consolidated subsidiaries and exclude netbacks from equity accounted entities. |
Six months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Oil and liquids ($/bbl) | ||||||||||||||||
Sales price | 93.21 | 93.59 | 93.21 | 93.59 | ||||||||||||
Royalties | 27.57 | 33.35 | - | - | ||||||||||||
Transportation | 1.52 | 1.43 | 2.15 | 2.23 | ||||||||||||
Operating costs | 22.03 | 22.91 | 31.30 | 35.59 | ||||||||||||
42.09 | 35.90 | 59.76 | 55.77 | |||||||||||||
Natural gas ($/mcf) | ||||||||||||||||
Sales price | 6.35 | 6.04 | 6.35 | 6.04 | ||||||||||||
Royalties | 1.48 | 1.50 | - | - | ||||||||||||
Transportation | 0.25 | 0.30 | 0.32 | 0.40 | ||||||||||||
Operating costs | 1.09 | 1.15 | 1.43 | 1.53 | ||||||||||||
3.53 | 3.09 | 4.60 | 4.11 | |||||||||||||
Total $/boe (6mcf=1boe) | ||||||||||||||||
Sales price | 56.69 | 53.35 | 56.69 | 53.35 | ||||||||||||
Royalties | 15.19 | 16.28 | - | - | ||||||||||||
Transportation | 1.49 | 1.70 | 2.03 | 2.45 | ||||||||||||
Operating costs | 11.80 | 11.69 | 15.83 | 16.25 | ||||||||||||
28.21 | 23.68 | 38.83 | 34.65 |
1. Netbacks do not include pipeline operations.
2. Amounts shown only represent netbacks from consolidated subsidiaries and exclude netbacks from equity accounted entities.
6
During the quarter, the Company’s average gross netback was $27.60/boe, 17% higher than 2013 due principally to higher realized liquids and gas prices in North America, higher liquids prices in Southeast Asia, lower transportation costs, partially offset by higher royalties and lower realized gas prices in Southeast Asia.
Talisman’s realized net price of $56.47/boe was 7% higher than 2013, due principally to higher realized prices on oil and liquids, which increased by 4% from 2013 and higher natural gas prices in North America.
The Company’s realized net sale price includes the impact of physical commodity contracts, but does not include the impact of financial commodity price derivatives discussed in the “Risk Management” section of this MD&A.
The corporate royalty rate was 28%, down from 29% in 2013 due principally to increased revenues from lower royalty rate jurisdictions.
COMMODITY PRICES AND EXCHANGE RATES1
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Oil and liquids ($/bbl) | ||||||||||||||||
North America | 66.11 | 65.84 | 67.04 | 64.92 | ||||||||||||
Southeast Asia | 110.99 | 101.07 | 110.67 | 106.54 | ||||||||||||
North Sea | 107.48 | 104.00 | 105.45 | 108.09 | ||||||||||||
Other | 107.76 | 98.29 | 106.07 | 104.62 | ||||||||||||
93.08 | 89.51 | 93.21 | 93.59 | |||||||||||||
Natural gas ($/mcf) | ||||||||||||||||
North America | 4.35 | 3.92 | 4.62 | 3.62 | ||||||||||||
Southeast Asia | 8.94 | 9.51 | 9.04 | 9.87 | ||||||||||||
North Sea | 7.82 | 30.67 | 8.67 | 14.80 | ||||||||||||
Other | - | - | - | - | ||||||||||||
6.18 | 6.12 | 6.35 | 6.04 | |||||||||||||
Company $/boe (6mcf=1boe) | 56.47 | 52.68 | 56.69 | 53.35 | ||||||||||||
Benchmark prices and foreign exchange rates | ||||||||||||||||
WTI �� (US$/bbl) | 102.99 | 94.22 | 100.84 | 94.30 | ||||||||||||
Dated Brent (US$/bbl) | 109.63 | 102.44 | 108.93 | 107.50 | ||||||||||||
WCS (US$/bbl) | 83.01 | 75.11 | 79.29 | 68.60 | ||||||||||||
LLS (US$/bbl) | 105.53 | 104.63 | 104.99 | 109.28 | ||||||||||||
NYMEX (US$/mmbtu) | 4.57 | 4.09 | 4.73 | 3.72 | ||||||||||||
AECO (C$/gj) | 4.44 | 3.40 | 4.47 | 3.16 | ||||||||||||
C$/US$ exchange rate | 1.09 | 1.02 | 1.10 | 1.02 | ||||||||||||
UK£/US$ exchange rate | 0.59 | 0.65 | 0.60 | 0.65 |
1. | 2013 represents prices from consolidated subsidiaries and excludes prices from equity investees. |
In North America, realized oil and liquids prices were relatively stable in 2014 compared to 2013. The realized liquids price in 2014 was more heavily weighted towards Natural Gas Liquids (NGL) products compared to 2013. In Southeast Asia, and the North Sea, realized oil and liquids prices increased by 10% and 3% respectively, consistent with increases in Brent pricing.
7
In North America, realized natural gas prices increased by 11% in 2014, consistent with increases in NYMEX prices. In Southeast Asia, realized natural gas prices decreased by 6% due principally to varying market allocation to the PSC gas contracts. A significant portion of natural gas pricing in Southeast Asia is linked to oil based indices. For example, Corridor gas prices averaged $9.77/mcf in the second quarter, where approximately 48% of sales are referenced to Duri crude and other oil indices on an energy equivalent basis. Due to these reasons, Talisman’s overall realized natural gas price of $6.18/mcf increased by 1% compared to 2013.
EXPENSES
Unit Operating Expenses1
Three months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
($/boe) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
North America | 8.07 | 8.78 | 9.60 | 10.38 | ||||||||||||
Southeast Asia | 11.56 | 10.82 | 17.42 | 16.96 | ||||||||||||
North Sea | 63.42 | 66.15 | 63.42 | 66.15 | ||||||||||||
Other | 10.05 | 10.16 | 19.09 | 19.34 | ||||||||||||
11.92 | 11.96 | 16.11 | 16.35 |
Six months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
($/boe) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
North America | 8.15 | 8.98 | 9.57 | 10.47 | ||||||||||||
Southeast Asia | 11.47 | 10.75 | 17.36 | 17.45 | ||||||||||||
North Sea | 58.95 | 52.66 | 58.95 | 52.66 | ||||||||||||
Other | 9.35 | 5.62 | 18.23 | 11.94 | ||||||||||||
11.80 | 11.69 | 15.83 | 16.25 |
1. | 2013 represents unit operating expenses from consolidated subsidiaries, excluding unit operating expenses from equity investees. |
Total Operating Expenses1
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
North America | 134 | 144 | 268 | 291 | ||||||||||||
Southeast Asia | 130 | 146 | 252 | 249 | ||||||||||||
North Sea | 71 | 86 | 169 | 157 | ||||||||||||
Other | 16 | 5 | 23 | 13 | ||||||||||||
351 | 381 | 712 | 710 |
1. | Represent operating expenses from consolidated subsidiaries, excluding operating expenses from equity investees. |
Total operating expenses decreased by $30 million due principally to the timing of liftings and asset dispositions in North America. These were partially offset by increased operating expenses in the rest of the world.
In North America, total operating expenses decreased by 7% to $134 million principally due to property dispositions in western Canada, and revisions to estimated costs in 2013, partially offset by increased production activity in the Eagle Ford. Unit operating expenses in North America decreased by 8% consistent with the reasons noted above and higher production volumes.
8
In Southeast Asia, total operating expenses decreased by 11% due primarily to the timing of liftings partially offset by the start-up of HST / HSD in Vietnam in the second quarter of 2013. Unit operating expenses increased by 7% due primarily to higher rates on new production in Vietnam and maintenance activities in Malaysia and Indonesia.
In the North Sea, operating expenses in Norway were down by 17% due principally to the timing of liftings, partially offset by increased maintenance costs at Brage. Unit operating costs in Norway decreased by 4% due to higher production volumes and lower operating costs for the reasons mentioned above.
In the rest of the world, total operating expenses were up by $11 million compared to the same period in 2013 due to increased long-term production testing in the Akacias field in Colombia and the ramp-up of EMK in Algeria in 2014.
Unit operating expense for the Company was stable compared to 2013 due to the reasons noted above.
Unit Depreciation, Depletion and Amortization (DD&A) Expense1
Three months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
($/boe) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
North America | 18.34 | 19.23 | 21.84 | 22.75 | ||||||||||||
Southeast Asia | 9.87 | 8.92 | 14.69 | 13.39 | ||||||||||||
North Sea | 43.25 | 33.38 | 43.23 | 33.38 | ||||||||||||
Other | 10.98 | 1.92 | 22.07 | 5.53 | ||||||||||||
15.67 | 15.14 | 20.53 | 19.77 |
Six months ended June 30 | ||||||||||||||||
Gross before royalties | Net of royalties | |||||||||||||||
($/boe) | 2014 | 2013 | 2014 | 2013 | ||||||||||||
North America | 17.10 | 18.58 | 20.09 | 21.65 | ||||||||||||
Southeast Asia | 9.97 | 8.28 | 15.38 | 13.33 | ||||||||||||
North Sea | 45.38 | 30.43 | 46.38 | 30.43 | ||||||||||||
Other | 10.80 | 5.63 | 21.67 | 11.47 | ||||||||||||
15.43 | 14.65 | 20.17 | 19.30 |
1. | Represents unit DD&A from consolidated subsidiaries, excluding unit DD&A from equity investees. |
9
Total DD&A Expense1
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
North America | 296 | 305 | 562 | 586 | ||||||||||||
Southeast Asia | 114 | 114 | 230 | 197 | ||||||||||||
North Sea | 50 | 44 | 127 | 90 | ||||||||||||
Other | 20 | 1 | 30 | 12 | ||||||||||||
480 | 464 | 949 | 885 |
1. | Represents DD&A expenses from consolidated subsidiaries, excluding DD&A expense from equity investees. |
Total DD&A expense increased by $16 million as a result of higher rates in the rest of the world and the North Sea. This was partially offset by decreased DD&A expense in North America.
DD&A expense in North America decreased by 3% principally due to the cessation of depletion associated with property dispositions, partially offset by higher production in Canada and the Eagle Ford. Unit DD&A expense decreased by 5% due to reserve additions in the Marcellus and impairments recorded on Canadian assets in the fourth quarter of 2013.
In Southeast Asia, DD&A expense remained stable and unit DD&A expense increased by 11%, due principally to the addition of higher DD&A rate properties from HST / HSD in Vietnam, partially offset by the timing of liftings.
In the North Sea, DD&A expense for Norway increased by 14% due principally to higher rates which resulted from increases in book value associated with increases in decommissioning liabilities at the end of 2013 and reserve revisions made at the end of 2013 related to Varg, Brage and Veslefrikk.
In the rest of the world, total DD&A expense increased due principally to the timing of liftings, increased production and the addition of higher DD&A rate properties in Algeria.
Unit DD&A expense for the Company increased by 4% to $15.67/boe due to the reasons noted above.
10
Impairment1
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
Impairment losses | ||||||||||||||||
North America | - | - | - | - | ||||||||||||
Southeast Asia | - | - | - | - | ||||||||||||
North Sea | 60 | - | 190 | 7 | ||||||||||||
Other | - | 12 | - | 12 | ||||||||||||
60 | 12 | 190 | 19 | |||||||||||||
Impairment reversals | ||||||||||||||||
North America | (32 | ) | - | (32 | ) | - | ||||||||||
Southeast Asia | - | - | - | - | ||||||||||||
North Sea | - | (21 | ) | - | (21 | ) | ||||||||||
Other | - | - | - | - | ||||||||||||
(32 | ) | (21 | ) | (32 | ) | (21 | ) | |||||||||
Net Impairment | 28 | (9 | ) | 158 | (2 | ) |
1. | Represents impairment expenses from consolidated subsidiaries, excluding impairment expenses from equity investees. |
During the three month period ended June 30, 2014, the Company recorded $60 million of impairment in Norway due to an increase in the decommissioning obligation and asset caused by a 1% decrease in the real discount rate used to measure decommissioning liabilities. The Company also recorded an impairment reversal of $32 million in North America, due to the estimated recoverable amount of assets held for sale exceeding their carrying amounts.
The exploration sub-period of the Company’s K44 license in Kurdistan is due to expire in September 2014. Prior to expiration, the Company intends to declare commerciality and file a development plan. The carrying value of the Company’s investment in K44 is $228 million at June 30, 2014.
Income (Loss) from Joint Ventures and Associates 1
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
TSEUK | (60 | ) | (16 | ) | (77 | ) | (68 | ) | ||||||||
Equion | 23 | 23 | 46 | 62 | ||||||||||||
Oleoducto Central S.A. (Ocensa) | - | 16 | - | 27 | ||||||||||||
(37 | ) | 23 | (31 | ) | 21 |
1. | Represents the Company’s proportionate interest in joint ventures and associates. |
During the three month period ended June 30, 2014, TSEUK recorded an impairment of $100 million (net to Talisman), due to an increase in the decommissioning obligation and asset caused by a decrease in the discount rated used to measure decommissioning liabilities.
The net loss in TSEUK increased by $44 million due principally to higher impairment, operating costs, and DD&A expense, partially offset by lower taxes.
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In December 2013, Talisman sold its 12.152% equity interest in the Ocensa pipeline. Talisman retained its crude oil transportation rights in the pipeline and retained its option to transport proprietary crude and to market any unused capacity to third parties.
Corporate and Other 1
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
General and administrative (G&A) expense | 105 | 111 | 210 | 214 | ||||||||||||
Dry hole expense | 12 | 69 | 28 | 69 | ||||||||||||
Exploration expense | 57 | 67 | 109 | 142 | ||||||||||||
Finance costs | 90 | 79 | 181 | 157 | ||||||||||||
Share-based payments expense (recovery) | 25 | 2 | (7 | ) | 24 | |||||||||||
(Gain) loss on held-for-trading financial instruments | 171 | (221 | ) | 231 | (141 | ) | ||||||||||
(Gain) loss on asset disposals | 5 | (59 | ) | (554 | ) | (59 | ) | |||||||||
Other income | 31 | 15 | 79 | 42 | ||||||||||||
Other expenses, net | 37 | 18 | 45 | 24 |
1. | Represents corporate and other expense from consolidated subsidiaries, excluding corporate and other expense from equity investees. |
G&A expense decreased by $6 million relative to 2013 due principally to lower workforce costs.
In the second quarter of 2014, Talisman recorded dry hole expense of $12 million due principally to the write-off of an exploration well in Australia.
Exploration expense decreased by $10 million due principally to reduced spending in the rest of the world.
Finance costs include interest on long-term debt (including current portion), other finance charges and accretion expense relating to decommissioning liabilities, less interest capitalized. The increase in finance costs is due principally to increased accretion expense in Norway as a result of Norway’s increased decommissioning liabilities, and a reduction in capitalized interest in Southeast Asia that resulted from HST / HSD in Vietnam becoming operational over the second quarter of 2013, partially offset by lower interest on long-term debt.
Share-based payments expense during the three month period ended June 30, 2014 was $25 million, due principally to expenses related to the long-term Performance Share Unit (PSU) plan and the issuance of a grant for the Restricted Share Unit (RSU) plan, partially offset by increased forfeitures of stock options and cash units.
Talisman recorded a loss on held-for-trading financial instruments of $171 million, due principally to an increase in oil and gas forward prices and higher settlement prices compared to March 31, 2014. See the ‘Risk Management’ section of this MD&A for further details concerning the Company’s financial instruments.
The increase of $16 million in other income was principally due to increased investment income of $7 million and interest income from TSEUK of $6 million.
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Other expense of $37 million includes a foreign exchange loss of $9 million, restructuring costs of $14 million and other miscellaneous expenses.
INCOME TAXES 1
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
Income (loss) before taxes | (163 | ) | 237 | 428 | 188 | |||||||||||
Less: Petroleum Revenue Tax (PRT) | ||||||||||||||||
Current | (1 | ) | 7 | 7 | 13 | |||||||||||
Deferred | (5 | ) | 1 | (2 | ) | 3 | ||||||||||
Total PRT | (6 | ) | 8 | 5 | 16 | |||||||||||
(157 | ) | 229 | 423 | 172 | ||||||||||||
Income tax expense (recovery) | ||||||||||||||||
Current income tax | 130 | 132 | 253 | 273 | ||||||||||||
Deferred income tax | (50 | ) | - | (84 | ) | 15 | ||||||||||
Total income tax expense | 80 | 132 | 169 | 288 | ||||||||||||
Effective income tax rate (%) | 51 | 58 | 40 | 167 |
1. | Represents income taxes from consolidated subsidiaries, excluding income taxes from equity investees. |
The effective tax rate is expressed as a percentage of income before taxes adjusted for PRT, which is deductible in determining taxable income. The effective tax rate in the second quarter of 2014 was impacted by pre-tax losses of $144 million in the North Sea where tax rates are principally 78%, and losses associated with held-for-trading financial instruments of $171 million, of which a significant portion are not deductible for tax purposes, partially offset by pre-tax income of $266 million in Southeast Asia where tax rates range from 30% to 55%.
In addition to the jurisdictional mix of income, the effective tax rate was also impacted by:
· | The effect of foreign exchange fluctuations in foreign denominated currency tax pools; and |
· | The non-recognition of deferred tax assets in the United States and Australia. |
Current tax expense of $130 million was consistent compared to 2013.
The deferred tax recovery of $50 million in the three month period ended June 30, 2014, compared to a deferred tax expense of $nil in the three month period ended June 30, 2013, was due principally to $60 million of impairment expense incurred in Norway.
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CAPITAL EXPENDITURES1,2
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
North America | 273 | 359 | 601 | 668 | ||||||||||||
Southeast Asia | 99 | 152 | 206 | 258 | ||||||||||||
North Sea1 | 37 | 71 | 89 | 208 | ||||||||||||
Other | 43 | 45 | 97 | 69 | ||||||||||||
Exploration and development expenditure from subsidiaries2 | 452 | 627 | 993 | 1,203 | ||||||||||||
Corporate, IS and Administrative | 16 | 19 | 20 | 10 | ||||||||||||
Acquisitions | 13 | - | 13 | - | ||||||||||||
Proceeds of dispositions | (52 | ) | (99 | ) | (1,392 | ) | (99 | ) | ||||||||
Net capital expenditure for subsidiaries | 429 | 547 | (366 | ) | 1,114 | |||||||||||
169 | 99 | 333 | 206 | |||||||||||||
TSEUK | ||||||||||||||||
Equion | 27 | 31 | 34 | 54 | ||||||||||||
Exploration and development expenditure from joint ventures3 | 196 | 130 | 367 | 260 | ||||||||||||
Net capital expenditure for consolidated subsidiaries and joint ventures | 625 | 677 | 1 | 1,374 |
1.Effective January 1, 2013, capital expenditures in the North Sea only relates to Norway.
2.Excludes exploration expense of $57 million (2013 - $67 million) for the three month period ended June 30, 2014 and $109 million (2013 - $142 million) for the six month period ended June 30, 2014.
3.Represents the Company’s proportionate interest, excluding exploration expensed of $1 million net in TSEUK (2013 - $5 million) for the three month period ended June 30, 2014 and $3 million net in TSEUK (2013 - $7 million) for the six month period ended June 30, 2014.
Capital expenditure, excluding exploration expense, decreased in the second quarter of 2014 compared to the same quarter in 2013 due principally to decreased spending in North America, Southeast Asia and the North Sea.
North America capital expenditures during the quarter totalled $273 million, a decrease of 24% from 2013. Of this, $242 million related to development activity, with the majority spent in the Eagle Ford, Marcellus and Edson areas. The remaining capital was mainly invested in exploration drilling activities, largely in the Duvernay.
In Southeast Asia, capital expenditures of $99 million included $68 million on development, with the majority spent in Indonesia and Malaysia. The majority of the $31 million for exploration was spent in Indonesia.
In Norway, capital expenditures of $37 million included $10 million of development activity at Brynhild and $21 million of non-operated development in Brage and Veselfrikk.
In the rest of the world, capital expenditures of $43 million included crude processing facilities in Colombia and exploration and evaluation activities in Colombia and the Kurdistan Region of Iraq.
In the TSEUK joint venture, net capital expenditures of $169 million consisted primarily of development activities at Montrose, Godwin, Auk North and Flyndre/Cawdor and $15 million for exploration drilling at Seagull. In the Equion joint venture, net capital expenditures of $27 million were principally all for development activities including the expansion of the Piedemonte facility.
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ASSET DISPOSALS
North America Dispositions
On April 16, 2014, Talisman sold non-core assets in western Canada for net proceeds of $43 million, resulting in a loss on disposal of $5 million ($5 million after tax).
In March 2014, Talisman completed the sale of its Montney acreage in northeast British Columbia for proceeds of $1.3 billion, resulting in a pre-tax gain of $567 million ($493 million after tax).
In May 2013, Talisman completed sales of non-core assets in western Canada for proceeds of $63 million, resulting in a pre-tax gain of $52 million ($39 million after tax).
Southeast Asia Disposition
On May 3, 2013, Talisman completed the sale of its 5.03% interest in the Offshore Northwest Java Production Sharing Contract (PSC) in Indonesia for net proceeds of $36 million, resulting in a pre-tax gain of $9 million ($3 million after tax).
ACQUISITIONS
Vietnam Acquisition
In July 2013, Talisman acquired a 55% working interest and operatorship of exploration and evaluation assets in Block 07/03 offshore Vietnam via two separate transactions with a total acquisition cost of $95 million. The block is adjacent to the Company's existing position in the Nam Con Son Basin.
ASSETS HELD FOR SALE
In June 2014, Talisman signed a purchase and sales agreement to sell non-core assets in western Canada for total cash consideration of C$120 million, before closing adjustments. The transaction is expected to close during the third quarter of 2014. These assets have been classified as held for sale in the condensed Consolidated Balance Sheet.
In accordance with IFRS, assets and liabilities associated with assets held for sale are aggregated and presented as current on the Consolidated Balance Sheet without restatement of comparative information. Operating results are included in the Consolidated Statement of Income until the transaction is complete.
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The following information relates to the assets classified as held for sale:
Balance Sheet of Assets Held for Sale
June 30, | 2014 | |||
Assets | ||||
Property, plant and equipment | 132 | |||
Goodwill | 2 | |||
Assets held for sale | 134 | |||
Liabilities | ||||
Decommissioning liabilities | 32 | |||
Deferred tax liabilities | 25 | |||
Liabilities associated with assets held for sale | 57 |
Results of Assets Held for Sale
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
($ millions) | ||||||||||||||||
Revenue | 15 | 15 | 30 | 26 | ||||||||||||
Operating expense | (6 | ) | (5 | ) | (12 | ) | (10 | ) | ||||||||
DD&A expenses¹ | (5 | ) | (9 | ) | (12 | ) | (26 | ) | ||||||||
Operating results before tax | 4 | 1 | 6 | (10 | ) | |||||||||||
Income tax expense | 1 | - | 2 | (2 | ) | |||||||||||
Operating results after tax | 3 | 1 | 4 | (8 | ) |
1. | DD&A expense ceased when assets transferred to assets held for sale June 1, 2014. |
Daily Average Production Volumes of Assets Held for Sale
Three months ended June 30 | Six months ended June 30 | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Natural gas (mmcf/d) | 38 | 48 | 40 | 48 | ||||||||||||
Total Daily Production (mboe/d) | 6 | 8 | 7 | 8 |
LIQUIDITY AND CAPITAL RESOURCES
Talisman’s gross debt at June 30, 2014 was $4.7 billion ($4.3 billion, net of cash and cash equivalents and bank indebtedness), compared to $5.2 billion ($4.9 billion, net of cash and cash equivalents and bank indebtedness) at December 31, 2013.
During the quarter, the Company generated $375 million of cash provided by operating activities and incurred capital expenditures of $470 million.
On an ongoing basis, Talisman plans to fund its capital program and acquisitions through a combination of cash on hand, cash provided by operating activities and cash proceeds from the disposition of non-core assets, and also by drawing on the Company’s credit facilities, issuing commercial paper, or issuing equity, long-term notes or debentures under the Company’s shelf prospectuses.
In May 2014, the Company renewed the universal shelf prospectus under the Multi-Jurisdictional Disclosure System pursuant to which it may issue up to $3.5 billion of debt securities, common shares, preferred shares, subscription receipts, warrants and units. The Company simultaneously also renewed the medium-term note shelf prospectus in Canada pursuant to which it may issue up to C$1 billion of medium-term notes in Canada. Both shelf prospectuses remain valid over a 25 month period.
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Talisman manages its liquidity requirements by use of both short-term and long-term cash forecasts, and by maintaining appropriate undrawn capacity under committed bank credit facilities. At June 30, 2014, Talisman had unsecured credit facilities totaling $3.2 billion, consisting of facilities of $3 billion (Facility No. 1), maturing March 19, 2019 and $200 million (Facility No. 2) maturing October 21, 2018. At June 30, 2014, $315 million of commercial paper was outstanding. Available borrowing capacity was $2.9 billion at June 30, 2014.
On May 5, 2014, Talisman amended certain terms of Facility No.1, converting the denomination to US dollars, extending the facility to $3 billion and extending the terms to five years maturing on March 19, 2019.
In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, most of which are uncommitted. At June 30, 2014, demand letters of credit guaranteed by the Company totaling $1.4 billion were issued, of which $1.3 billion were issued from uncommitted facilities. Of that total, $1.1 billion, issued from shared facilities with Addax, is provided as security for the costs of decommissioning obligations in the UK, as described below. The remaining outstanding letters of credit relate primarily to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations in other areas.
TSEUK is required to provide letters of credit as security in relation to certain decommissioning obligations in the UK pursuant to contractual arrangements under Decommissioning Security Agreements (DSAs). At the commencement of the joint venture, Addax assumed 49% of the decommissioning obligations of TSEUK supported by an unconditional and irrevocable guarantee from Addax’s parent company, Sinopec.
During January 2014, all remaining letters of credit issued under legacy facilities were replaced by letters of credit totalling $1 billion from the shared facilities of which Talisman’s share is 51%. As a result of this change, as at June 30, 2014, TSEUK has $2.6 billion of demand shared facilities in place under which letters of credit of $2.1 billion have been issued.
On July 1, 2014, total letters of credit issued by TSEUK have been reduced to $1.8 billion as a result of letters of credit that expired on June 30, 2014 which were renewed and posted on an after-tax basis. The Company guarantees 51% of all letters of credit issued under these shared facilities.
The Company has also granted guarantees to various beneficiaries in respect of decommissioning obligations of TSEUK.
The United Kingdom Government passed legislation in 2013 which provides for a contractual instrument, known as a Decommissioning Relief Deed, for the Government to guarantee tax relief on decommissioning costs at 50%, allowing security under DSAs to be posted on an after tax basis and reducing the amount of letters of credit required to be posted correspondingly. TSEUK has entered into a Decommissioning Relief Deed with the United Kingdom Government and has commenced negotiations with counterparties to amend all DSAs accordingly. The Company has replaced certain letters of credit that expired on June 30, 2014 on an after tax basis and has the objective of completing this process for the remaining letters of credit during 2014.
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Any changes to decommissioning estimates influence the value of letters of credit to be provided pursuant to the DSAs. In addition, the extent to which shared facility capacity is available, and the cost of that capacity, is influenced by the Company’s investment grade credit rating.
Talisman manages its balance sheet with reference to its liquidity and a debt-to-cash flow ratio. The main factors in assessing the Company’s liquidity are cash flow, including cash flow from equity accounted entities (defined in accordance with the Company’s debt covenant as cash provided by operating activities before adjusting for changes in non-cash working capital, and exploration expenditure), cash provided by and used in investing activities and available bank credit facilities. The debt-to-cash flow ratio is calculated using debt (calculated by adding the gross debt and bank indebtedness, production payments and finance lease) divided by cash flow for the year.
The Company is in compliance with all of its debt covenants. The Company’s principal financial covenant under its primary bank credit facility is a debt-to-cash flow ratio of less than 3.5:1, calculated quarterly on a trailing 12-month basis as of the last day of each fiscal quarter. For the trailing 12-month period ended June 30, 2014, the debt-to-cash flow ratio was 1.9:1.
The Company established a US commercial paper program in November 2011. The authorized amount under this program is $1 billion. The amount available under the commercial paper program is limited to the availability of backup funds under the Company’s bank credit facilities. At June 30, 2014 the amount of commercial paper outstanding was $315 million and the average interest rate on outstanding commercial paper was 0.7127%. The classification of commercial paper as a current liability at June 30, 2014 reflects management’s intent with respect to its repayment.
A significant proportion of Talisman’s accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At June 30, 2014, approximately 80% of the Company's trade accounts receivable were aged less than 90 days and the largest single counterparty exposure, accounting for 4% of the total, was with a highly rated counterparty. Concentration of counterparty credit risk is mitigated by having a broad domestic and international customer base of highly rated counterparties.
The Company also has credit risk arising from cash and cash equivalents held with banks and financial institutions. The Company’s policy allows it to deposit cash balances at financial institutions subject to a sliding scale limit, depending on creditworthiness. The maximum credit exposure associated with financial assets is the carrying values.
At June 30, 2014, there were 1,036,205,268 common shares outstanding, of which 2,374,142 were held in trust by the Company resulting in 1,033,831,126 common shares outstanding for accounting purposes. During the three month period ended June 30, 2014, Talisman declared common share dividends of $0.0675 per share for an aggregate dividend of $70 million. Subsequent to June 30, 2014, no stock options were exercised for shares and no common shares were purchased and held in trust for the long-term PSU plan. There were 1,033,831,126 common shares outstanding at July 24, 2014.
At June 30, 2014, there were 8,000,000 Series 1 preferred shares outstanding. Holders of Series 1 preferred shares are entitled to receive cumulative quarterly fixed dividends of 4.2% per annum for the initial period ending December 31, 2016, if, as, and when declared by the Board of Directors. Thereafter, the dividend rate will be reset every five years at a rate equal to the five-year Government of Canada bond yield plus 2.77%. During the three month period ended June 30, 2014, Talisman declared preferred share dividends of C$0.2625 per share for an aggregate dividend of $2 million.
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At June 30, 2014, there were 39,651,845 stock options, 11,952,769 RSUs, 2,735,329 deferred share units (DSU) and 10,646,722 long-term PSUs outstanding.
Subsequent to June 30, 2014, no stock options were granted, surrendered for cash, or exercised for shares, and 741,108 were forfeited with 38,910,737 outstanding at July 24, 2014. Subsequent to June 30, 2014, 69,056 PSUs were granted and 96,825 PSUs were forfeited, with 10,618,953 outstanding at July 24, 2014. Subsequent to June 30, 2014, 105,135 RSUs were granted, including reinvested dividends, 62,214 were exercised and 182,329 were forfeited with 11,813,361 outstanding at July 24, 2014. There were no DSUs granted subsequent to June 30, 2014, 40,078 DSUs were exercised, with 2,695,251 outstanding at July 24, 2014.
The Company may purchase shares on the open market to satisfy its obligation to deliver common shares to settle long-term PSUs, which are held in trust. The 2011 long-term PSU grant vested on December 31, 2013 and was settled in March 2014 based on the vesting of 75% of the PSUs granted as approved by the Board of Directors.
During the six month period ended June 30, 2014, no common shares were purchased on the open market (During the same period in 2013 – no common shares were purchased). Between July 1 and July 24, 2014, no common shares were purchased on the open market.
Talisman continually monitors its portfolio of assets and investigates business opportunities in the oil and gas sector. The Company may make acquisitions, investments or dispositions, some of which may be material. In connection with any acquisition or investment, Talisman may incur debt or issue equity.
For additional information regarding the Company’s liquidity and capital resources, refer to notes 18 and 21 to the 2013 audited Consolidated Financial Statements and notes 13 and 15 to the interim condensed Consolidated Financial Statements.
SENSITIVITIES
Talisman’s financial performance is affected by factors such as changes in production volumes, commodity prices and exchange rates. The estimated annualized impact of these factors for 2014 (excluding the effect of derivative contracts) is summarized in the following table, based on a Dated Brent oil price of approximately $105/bbl, a NYMEX natural gas price of approximately $4.45/mmbtu and exchange rates of US$0.90=C$1 and UK£1=US$1.65.
(millions of $) | Net Income | Cash Provided by Operating Activities3 | ||||||
Volume changes | ||||||||
Oil – 10,000 bbls/d | 70 | 135 | ||||||
Natural gas – 60 mmcf/d | 15 | 65 | ||||||
Price changes1 | ||||||||
Oil – $1.00/bbl | 20 | 5 | ||||||
Natural gas (North America)2 – $0.10/mcf | 15 | 5 | ||||||
Exchange rate changes | ||||||||
US$/C$ decreased by US$0.01 | (5 | ) | (5 | ) | ||||
US$/UK£ increased by US$0.02 | - | - |
1. | The impact of price changes excludes the effect of commodity derivatives. See specific commodity derivative terms in the ‘Risk Management’ section of this MD&A, and note 16 to the interim condensed Consolidated Financial Statements. |
2. | Price sensitivity on natural gas relates to North American natural gas only. The Company’s exposure to changes in the natural gas prices in Norway and Malaysia/Vietnam and Colombia is not material. Most of the natural gas price in Indonesia is based on the price of crude oil and, accordingly, has been included in the price sensitivity for oil except for a small portion which is sold at a fixed price. |
3. | Changes in cash flow provided by operating activities excludes TSEUK and Equion due to the application of equity accounting. |
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COMMITMENTS AND OFF-BALANCE SHEET ARRANGEMENTS
As part of its normal business, the Company has entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity, some of which are reflected as liabilities in the Consolidated Financial Statements at year-end. The principal commitments of the Company are in the form of debt repayments, decommissioning obligations, lease commitments relating to corporate offices and ocean-going vessels, firm commitments for gathering, processing and transmission services, minimum work commitments under various international agreements, other service contracts and fixed price commodity sales contracts.
Additional disclosure of the Company’s debt repayment obligations can be found in note 18 to the 2013 audited Consolidated Financial Statements and note 17 to the interim condensed Consolidated Financial Statements. A discussion of the Company’s derivative financial instruments and commodity sales contracts can be found in the “Risk Management” section of this MD&A.
During the six month period ended June 30, 2014, as a result of the sale of the Company’s Montney acreage and non-core assets in western Canada, there was a total of $339 million decrease in the Company’s expected future commitments, including a $286 million decrease in transportation and processing commitments, a $50 million decrease in PP&E and E&E asset commitments, and a $3 million decrease in office lease commitments. There have been no additional significant changes in the Company’s expected future commitments, and the timing of those payments, since December 31, 2013.
TRANSACTIONS WITH RELATED PARTIES
In June 2014, the shareholders of TSEUK agreed to subscribe for common shares of TSEUK in the amount of $1.26 billion, of which Talisman’s share was $643 million, which settled shareholder loans of $1.24 billion and accrued interest of $18 million, of which Talisman’s share was $634 million and $9 million, respectively.
In addition, the shareholders of TSEUK provided an equity funding facility totaling $1.2 billion to TSEUK in June 2014, of which Talisman is committed to $612 million, for the purpose of funding capital, decommissioning and operating expenditures of TSEUK. TSEUK may fund operating expenditures under this facility to a maximum amount of $150 million. This facility expires on June 30, 2015.
RISK MANAGEMENT
Talisman monitors its exposure to variations in commodity prices, interest rates and foreign exchange rates. In response, Talisman periodically enters into physical delivery transactions for commodities of fixed or collared prices and into derivative financial instruments to reduce exposure to unfavourable movements in commodity prices, interest rates and foreign exchange rates. The terms of these contracts or instruments may limit the benefit of favourable changes in commodity prices, interest rates and currency values, and may result in financial or opportunity loss due to delivery commitments, royalty rates and counterparty risks associated with contracts. The Company has established a system of internal controls to minimize risks associated with its derivatives program and credit risk associated with derivatives counterparties.
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The accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 3(q) to the 2013 audited Consolidated Financial Statements. Derivative financial instruments and commodity sales contracts outstanding at June 30, 2014, including their respective fair values, are detailed in note 16 to the interim condensed Consolidated Financial Statements.
The Company has elected not to designate any commodity price derivative contracts entered into as hedges for accounting purposes. These derivatives are classified as held-for-trading financial instruments and are measured at fair value with changes in fair value recognized in net income. This can potentially increase the volatility of net income.
Commodity Price Derivative Financial Instruments
The Company had the following commodity price derivative contracts outstanding at June 30, 2014, none of which are designated as hedges:
Two-way collars (Oil) | Term | bbls/d | Floor/ceiling $/bbl | ||||||
Dated Brent oil index | 2014 Jul – Dec | 10,000 | 95.00/110.07 | ||||||
Dated Brent oil index | 2014 Jul – Dec | 10,000 | 90.00/105.22 | ||||||
NYMEX WTI oil index | 2014 Jul – Dec | 5,000 | 80.00/95.00 | ||||||
Dated Brent oil index | 2015 Jan – Dec | 5,000 | 90.00/100.01 | ||||||
NYMEX WTI oil index | 2015 Jan – Dec | 5,000 | 80.00/95.02 | ||||||
Dated Brent oil index | 2015 Jan – Dec | 20,000 | 90.00/106.16 | ||||||
Dated Brent oil index | 2016 Jan – Dec | 5,000 | 90.00/108.00 | ||||||
NYMEX WTI oil index | 2016 Jan – Dec | 5,000 | 85.00/95.95 |
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Fixed priced swaps (Oil) | Term | bbls/d | $/bbl | ||||||
NYMEX WTI oil index | 2014 Jul - Dec | 2,500 | 91.91 | ||||||
Dated Brent oil index | 2014 Jul - Dec | 10,000 | 104.02 | ||||||
NYMEX WTI oil index | 2014 Jul - Dec | 10,000 | 94.28 | ||||||
Dated Brent oil index | 2014 Jul - Dec | 10,000 | 103.31 | ||||||
Dated Brent oil index | 2014 Jul - Dec | 8,000 | 111.79 | ||||||
Dated Brent oil index | 2015 Jan - Dec | 10,000 | 100.46 | ||||||
Dated Brent oil index | 2015 Jan - Dec | 1,000 | 104.00 | ||||||
Dated Brent oil index | 2015 Jan - Dec | 9,000 | 100.59 | ||||||
NYMEX WTI oil index | 2015 Jan - Dec | 5,000 | 96.36 | ||||||
Dated Brent oil index | 2016 Jan - Dec | 10,000 | 98.01 | ||||||
Dated Brent oil index | 2016 Jan - Dec | 5,000 | 100.29 | ||||||
Dated Brent oil index | 2016 Jan - Dec | 5,750 | 102.98 | ||||||
Two-way collars (Gas) | Term | mcf/d | Floor/ceiling $/mcf | ||||||
NYMEX HH LD | 2014 Jul - Dec | 94,936 | 4.21/4.71 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.21/4.64 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.21/4.99 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 47,468 | 4.23/4.87 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 94,936 | 4.21/5.06 | ||||||
NYMEX HH LD | 2016 Jan - Dec | 47,468 | 4.21/4.75 | ||||||
NYMEX HH LD | 2016 Jan - Dec | 47,468 | 4.21/4.87 |
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Fixed priced swaps (Gas) | Term | mcf/d | $/mcf | ||||||
NYMEX HH LD | 2014 Jul - Oct | 47,468 | 4.17 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.24 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.25 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.34 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.42 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.44 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.29 | ||||||
NYMEX HH LD | 2014 Jul - Dec | 47,468 | 4.43 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 47,468 | 4.54 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 47,468 | 4.39 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 47,468 | 4.39 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 47,468 | 4.48 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 47,468 | 4.53 | ||||||
NYMEX HH LD | 2015 Jan - Dec | 47,468 | 4.55 | ||||||
NYMEX HH LD | 2016 Jan - Dec | 47,468 | 4.48 | ||||||
NYMEX HH LD | 2016 Jan - Dec | 42,721 | 4.55 |
Fixed priced swaps (Power) | Term | MWh | $CAD/MWh | ||||||
Alberta Power | 2014 Jul - Dec | 7 | 74.66 | ||||||
Alberta Power | 2015 Jan - Dec | 5 | 73.72 | ||||||
Alberta Power | 2016 Jan - Dec | 2 | 73.83 | ||||||
Alberta Power | 2017 Jan - Dec | 1 | 74.75 | ||||||
Alberta Power | 2018 Jan - Dec | 1 | 74.75 |
Subsequent to June 30, 2014, the Company entered into a Dated Brent swap for 2016 of 4,250 bbls/d for $102.98/bbl, a Western Canadian Select (WCS) differential swap for the fourth quarter of 2014 of 5,000 bbls/d for ($21.48)/bbl, a WCS differential swap for the first quarter of 2015 of 5,000 bbls for ($21.48)/bbl.
Interest Rate Swaps
In order to swap a portion of the $375 million 5.125% notes due 2015 to floating interest rates, the Company entered into fixed-to-floating interest rate swap contracts with a total notional amount of $300 million that expire on May 15, 2015. These swap contracts require Talisman to pay interest at a rate of three month US$ LIBOR plus 0.433% while receiving payments of 5.125% semi-annually.
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USE OF ESTIMATES AND JUDGMENTS
The preparation of financial statements requires management to make estimates and assumptions that affect reported assets and liabilities, disclosures of contingencies and revenues and expenses. Management is required to adopt accounting policies that require the use of significant estimates and judgment. Actual results could differ materially from those estimates. Judgments and estimates are reviewed by management on a regular basis.
Decommissioning liabilities are measured based on the estimated cost of abandonment discounted to its net present value using a weighted average credit-adjusted risk free rate, which was 2.8% at June 30, 2014 (December 31, 2013 – 3.8%). Due to this rate decrease, the net present value of the decommissioning liability increased by $178 million in the second quarter of 2014.
For additional information regarding the use of estimates and judgments refer to the notes to the audited Consolidated Financial Statements and Annual MD&A for the year ended December 31, 2013.
CHANGES IN ACCOUNTING POLICIES
a) Accounting Policies Used
The interim condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the 2013 annual Consolidated Financial Statements except for the following:
Offsetting Financial Assets and Financial Liabilities
· | IAS 32 Offsetting Financial Assets and Financial Liabilities - Financial Instruments Presentation. The amended standard requires entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The scope includes derivatives, sale and repurchase agreements and reverse sale and repurchase agreements and securities borrowing and securities lending agreements. The amendments to IAS 32 are effective for annual periods beginning on or after January 1, 2014 and require retrospective application. As the Company is not netting any significant amounts related to financial instruments and does not have any significant offsetting arrangements, the amendment does not have an impact on the Company’s financial statements. |
· | IAS 36 Impairment of Assets – Amendments to IAS 36. The amended standard requires entities to disclose the recoverable amount of an impaired Cash Generating Unit (CGU). The amendments to IAS 36 are effective for annual periods beginning on or after January 1, 2014 and require retrospective application. This standard does not have an impact on the Company’s financial position or performance. |
· | IFRIC 21 Levies - Interpretation of IAS 37 Provisions, contingent liabilities and assets: IAS 37 sets out criteria for the recognition of a liability, one of which is the requirement for the entity to have a present obligation as a result of a past event. The interpretation clarifies that the obligation that gives rise to the liability to pay a levy is the activity described in the relevant legislation that triggers the payment of the levy. Talisman reviewed payments of levies and concluded that the application of the standard does not have a significant impact on the Company. |
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b) Accounting Pronouncements Not Yet Adopted
The Company continues to assess the impact of adopting the following pronouncements.
Financial Instruments
· | IFRS 9 Financial Instruments: IFRS 9 sets out requirements for the classification and measurement of financial assets in November 2009, and was updated in October 2010 to incorporate financial liabilities. In November 2013, the IASB issued amendments to include the new general hedge accounting model. IFRS 9 (2013) does not yet have a mandatory effective date, but early adoption is allowed. At its February 2014 meeting, IASB tentatively decided that the mandatory effective date of IFRS 9 will be for annual period beginning on or after January 1, 2018. The Company continues to evaluate the impact of this standard. |
Revenue
· | IFRS 15 Revenue from Contracts with Customers: IFRS 15 specifies how and when to recognize revenue as well as requiring entities to provide users of financial statements with more informative, relevant disclosures. The standard supersedes IAS 18 Revenue, IAS 11 Construction Contracts, and a number of revenue-related interpretations. IFRS 15 will be effective for annual periods beginning on or after January 1, 2017. Application of the standard is mandatory and early adoption is permitted. The Company has not yet determined the impact of the amendments on the Company’s financial statements. |
INTERNAL CONTROL OVER FINANCIAL REPORTING
There have been no significant changes in Talisman’s internal control over financial reporting during the three month period ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Talisman utilizes the original Internal Control - Integrated Framework (1992) issued by the Committee of the Sponsoring Organizations of the Treadway Commission (COSO) to design and evaluate its internal control over financial reporting. In May 2013, COSO updated the Internal Control – Integrated Framework which will supersede the 1992 Framework on December 15, 2014.
LEGAL PROCEEDINGS
From time to time, Talisman is the subject of litigation arising out of the Company's operations. Damages claimed under such litigation may be material or may be indeterminate and the outcome of such litigation may materially impact the Company’s financial condition or results of operations. While Talisman assesses the merits of each lawsuit and defends itself accordingly, the Company may be required to incur significant expenses or devote significant resources to defend itself against such litigation. These claims are not expected to have a material impact on the Company's financial position.
REGULATORY DEVELOPMENT
Dodd-Frank Act
In 2010, the US Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act or the Act) was signed into law. The Dodd-Frank Act provides for numerous new substantive requirements in areas such as the disclosure of payments made to foreign governments, rules regarding the use of credit ratings, and corporate governance and executive compensation reforms, among others, some of which apply to Talisman as a foreign private issuer. Talisman will continue to assess the effect on the Company of the Dodd-Frank Act and related rules. The SEC has yet to adopt the rules relating to pay-for-performance, pay parity, hedging and executive compensation clawbacks.
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In August 2012, the SEC adopted rules to implement Section 1504 of the Dodd-Frank Act, requiring resource extraction issuers to disclose payments made to the US federal government or a foreign government (including a department, agent or instrumentality of a foreign government or a company owned by a foreign government) in their annual reports. On July 2, 2013, the US District Court for the District of Colombia vacated these rules, meaning that the rules are no longer in effect. As at July 24, 2014, the SEC had not issued new or revised rules in response to the Court’s ruling.
ADVISORIES
Forward-Looking Statements
This interim MD&A contains 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, but is not limited to, statements regarding:
· | Business strategy, plans, and priorities; |
· | The estimated impact on Talisman’s financial performance from changes in production volumes, commodity prices and exchange rates; |
· | Potential effects of the hedging program; |
· | Expected sources of capital to fund the Company’s capital program and potential acquisitions, investments or dispositions; |
· | Expected future payment commitments; |
· | Expected closing of the non-core asset sale in western Canada; |
· | Expected timing of securing amendments to all DSAs pursuant to signing of the Decommissioning Relief Deed; and, |
· | Other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance. |
Statements concerning oil and gas reserves contained in this interim MD&A may be deemed to be forward-looking information as they involve the implied assessment that the resources described can be profitably produced in the future.
The factors or assumptions on which the forward-looking information is based include: assumptions inherent in current guidance; projected capital investment levels; the flexibility of capital spending plans and the associated sources of funding; the successful and timely implementation of capital projects; the continuation of tax, royalty and regulatory regimes; ability to obtain regulatory and partner approval; commodity price and cost assumptions; and other risks and uncertainties described in the filings made by the Company with securities regulatory authorities. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct. Forward-looking information for periods past 2014 assumes escalating commodity prices. Closing of any transactions will be subject to receipt of all necessary regulatory approvals and completion of definitive agreements.
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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 MD&A. 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; |
· | Risks and uncertainties involving geology of oil and gas deposits; |
· | Risks associated with project management, project delays and / or cost overruns; |
· | Uncertainty related to securing sufficient egress and access to markets; |
· | 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, including decommissioning liabilities; |
· | Risks related to strategic and capital allocation decisions, including 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, interest rates and tax or royalty rates; |
· | The outcome and effects of any future acquisitions and dispositions; |
· | Health, safety, security and environmental risks, including risks related to the possibility of major accidents; |
· | Environmental regulatory and compliance risks, including with respect to greenhouse gases and hydraulic fracturing; |
· | Uncertainties as to access to capital, including the availability and cost of credit and other financing, and changes in capital markets; |
· | Risks in conducting foreign operations (for example, civil, political and fiscal instability and corruption); |
· | Risks related to the attraction, retention and development of personnel; |
· | Changes in general economic and business conditions; |
· | The possibility that government policies, regulations 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 AIF and Annual Report. In addition, information is available in the Company’s other reports on file with Canadian securities regulatory authorities and the 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.
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Advisory – Oil and Gas Information
Talisman makes reference to production volumes throughout this interim MD&A. Where not otherwise indicated, 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.
Talisman also discloses netbacks in this interim MD&A. Netbacks per boe are calculated by deducting from sales price associated royalties, operating and transportation costs.
Non-Core Assets
In this MD&A, all references to “core” or “non-core” assets and properties align with the Company’s current public disclosures regarding its assets and properties.
Use of ‘boe’
Throughout this interim MD&A, the calculation of barrels of oil equivalent (boe) is 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. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6mcf:1bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.
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ABBREVIATIONS AND DEFINITIONS
The following abbreviations and definitions are used in this MD&A:
AIF | Annual Information Form |
bbl | barrel |
bbls | barrels |
bbls/d | barrels per day |
bcf | billion cubic feet |
boe | barrels of oil equivalent |
boe/d | barrels of oil equivalent per day |
COSO | Committee of the Sponsoring Organizations of the Treadway Commission |
C$ | Canadian dollar |
DD&A | Depreciation, depletion and amortization |
DSA | Decommissioning Security Agreements |
DSU | Deferred share unit |
E&E | Exploration and evaluation |
EU | European Union |
G&A | General and administrative |
GAAP | Generally Accepted Accounting Principles |
GHG | Greenhouse gas emissions |
gj | Gigajoule |
IFRS | International Financial Reporting Standards |
LIBOR | London Interbank Offered Rate |
LLS | Light Louisiana Sweet |
LNG | Liquefied Natural Gas |
mbbls/d | thousand barrels per day |
mboe/d | thousand barrels of oil equivalent per day |
mcf | thousand cubic feet |
mcf/d | thousand cubic feet per day |
mmbbls | million barrels |
mmboe | million barrels of oil equivalent |
mmbtu | million British thermal units |
mmcf/d | million cubic feet per day |
mmcfe/d | million cubic feet equivalent per day |
MWh | megawatt hour |
NGL | Natural Gas Liquids |
NI | National Instrument |
NOK | Norwegian kroner |
NYMEX | New York Mercantile Exchange |
PGN | PT Perusahaan Gas Negara (Persero), Tbk |
PP&E | Property, plant and equipment |
PRT | Petroleum Revenue Tax |
PSC | Production Sharing Contract |
PSU | Performance share unit |
RSU | Restricted share unit |
SEC | US Securities and Exchange Commission |
tcf | trillion cubic feet |
UK | United Kingdom |
UK£ | Pound sterling |
US | United States of America |
US$ or $ | United States dollar |
WCS | Western Canadian Select |
WTI | West Texas Intermediate |
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Gross acres means the total number of acres in which Talisman has a working interest. Net acres means the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
Gross production means Talisman’s interest in production volumes (through working interests and royalty interests) before the deduction of royalties. Net production means Talisman’s interest in production volumes after deduction of royalties payable by Talisman.
Gross wells means the total number of wells in which the Company has a working interest. Net wells means the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.
Conversion and equivalency factors
Imperial | Metric | |
1 ton | = | 0.907 tonnes |
1 acre | = | 0.40 hectares |
1 barrel | = | 0.159 cubic metres |
1 cubic foot | = | 0.0282 cubic metres |
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