Exhibit 99.2
Management’s Discussion and Analysis (“MD&A”)
(May 12, 2017)
GENERAL
This MD&A should be read in conjunction with the unaudited condensed consolidated financial statements (“Consolidated Financial Statements”), of Repsol Oil & Gas Canada Inc. (“ROGCI” or “the Company”), as at and for the three months ended March 31, 2017 and 2016, and the 2016 Restated MD&A and audited Restated Consolidated Financial Statements of the Company. The Company’s unaudited 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”).
The Company’s financial statements are prepared on a consolidated basis and include the accounts of the Company and its subsidiaries. Substantially all of the Company’s activities are conducted jointly with others, and the unaudited condensed Consolidated Financial Statements reflect only the Company’s proportionate interest in such activities, with the exception of the Company’s investments in Repsol Sinopec Resources UK Limited (“RSRUK”) and Equion Energía Limited (“Equion”) which are accounted for using the equity method.
All comparisons are between the three months ended March 31, 2017 and 2016, 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 the Company’s Annual Information Form (AIF), can be found on the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com. The Company’s Annual Report on Form 40-F may be found in the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) database at www.sec.gov.
FINANCIAL AND OPERATING HIGHLIGHTS
|
| Three months ended |
| ||||||||||||||
|
| Q1 |
| Q4 |
| Q3 |
| Q2 |
| Q1 |
| Q4 |
| Q3 |
| Q2 |
|
(millions of $, unless otherwise stated) |
| 2017 |
| 2016 |
| 2016 |
| 2016 |
| 2016 |
| 2015 |
| 2015 |
| 2015 |
|
Total revenue and other income from continuing operations1 |
| 568 |
| 679 |
| 313 |
| 316 |
| 469 |
| 145 |
| 345 |
| 556 |
|
Total revenue and other income from discontinued operations2 |
| — |
| — |
| — |
| — |
| — |
| — |
| 38 |
| 83 |
|
Total revenue and other income |
| 568 |
| 679 |
| 313 |
| 316 |
| 469 |
| 145 |
| 383 |
| 639 |
|
Net income (loss) from continuing operations |
| — |
| 262 |
| (323 | ) | (306 | ) | (145 | ) | (628 | ) | (899 | ) | (888 | ) |
Net income (loss) from discontinued operations2 |
| — |
| — |
| — |
| — |
| — |
| — |
| 112 |
| (364 | ) |
Net income (loss) |
| — |
| 262 |
| (323 | ) | (306 | ) | (145 | ) | (628 | ) | (787 | ) | (1,252 | ) |
Net income (loss) attributable to shareholder |
| 7 |
| 262 |
| (323 | ) | (306 | ) | (145 | ) | (628 | ) | (899 | ) | (888 | ) |
Net loss attributable to non-controlling interest3 |
| (7 | ) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Net income (loss) per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
| — |
| 0.14 |
| (0.18 | ) | (0.17 | ) | (0.08 | ) | (0.59 | ) | (0.75 | ) | (1.20 | ) |
Net income (loss) from continuing operations per common share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted |
| — |
| 0.14 |
| (0.18 | ) | (0.17 | ) | (0.08 | ) | (0.59 | ) | (0.86 | ) | (0.85 | ) |
Daily average production from Consolidated Subsidiaries and Joint Ventures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and liquids (mbbls/d) |
| 112 |
| 106 |
| 116 |
| 112 |
| 119 |
| 127 |
| 120 |
| 127 |
|
Natural gas (mmcf/d) |
| 1,233 |
| 1,230 |
| 1,223 |
| 1,252 |
| 1,334 |
| 1,359 |
| 1,299 |
| 1,321 |
|
Continuing operations (mboe/d) |
| 332 |
| 325 |
| 334 |
| 335 |
| 357 |
| 369 |
| 351 |
| 362 |
|
Discontinued operations (mboe/d) |
| — |
| — |
| — |
| — |
| — |
| — |
| 13 |
| 16 |
|
Total mboe/d |
| 332 |
| 325 |
| 334 |
| 335 |
| 357 |
| 369 |
| 364 |
| 378 |
|
(1) Includes other income and income from joint ventures, after tax.
(2) Discontinued operations are the results associated with the Norway disposition.
(3) Repsol Oil & Gas USA LLC. (“ROGUSA”) non-controlling interest.
The net loss was $145 million lower than 2016 primarily due to higher commodity prices, lower operating expense, dry hole expense, exploration expense, G&A expense, finance costs and other expense. This was partially offset by income tax changes, lower other income and after-tax income from joint ventures.
DAILY AVERAGE PRODUCTION
|
| Three months ended March 31 |
| ||||||
|
| Gross before royalties |
| Net of royalties |
| ||||
|
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
Oil and liquids from Consolidated Subsidiaries (mbbls/d) |
|
|
|
|
|
|
|
|
|
North America |
| 34 |
| 39 |
| 30 |
| 33 |
|
Southeast Asia |
| 25 |
| 32 |
| 15 |
| 23 |
|
Other1 |
| 15 |
| 11 |
| 9 |
| 6 |
|
|
| 74 |
| 82 |
| 54 |
| 62 |
|
Oil and liquids from Joint Ventures (mbbls/d) |
|
|
|
|
|
|
|
|
|
RSRUK |
| 25 |
| 23 |
| 25 |
| 23 |
|
Equion |
| 13 |
| 14 |
| 10 |
| 11 |
|
|
| 38 |
| 37 |
| 35 |
| 34 |
|
Total oil and liquids from Consolidated Subsidiaries and Joint Ventures (mbbls/d) |
| 112 |
| 119 |
| 89 |
| 96 |
|
Natural gas from Consolidated Subsidiaries (mmcf/d) |
|
|
|
|
|
|
|
|
|
North America |
| 768 |
| 796 |
| 668 |
| 712 |
|
Southeast Asia |
| 441 |
| 494 |
| 333 |
| 379 |
|
|
| 1,209 |
| 1,290 |
| 1,001 |
| 1,091 |
|
Natural gas from Joint Ventures (mmcf/d) |
|
|
|
|
|
|
|
|
|
RSRUK |
| 4 |
| 5 |
| 4 |
| 5 |
|
Equion |
| 20 |
| 39 |
| 20 |
| 30 |
|
|
| 24 |
| 44 |
| 24 |
| 35 |
|
Total natural gas from Consolidated Subsidiaries and Joint Ventures (mmcf/d) |
| 1,233 |
| 1,334 |
| 1,025 |
| 1,126 |
|
Total daily production from Consolidated Subsidiaries (mboe/d) |
|
|
|
|
|
|
|
|
|
North America |
| 171 |
| 181 |
| 149 |
| 160 |
|
Southeast Asia |
| 104 |
| 120 |
| 75 |
| 90 |
|
Other |
| 15 |
| 11 |
| 9 |
| 6 |
|
|
| 290 |
| 312 |
| 233 |
| 256 |
|
Total daily production from Joint Ventures (mboe/d) |
|
|
|
|
|
|
|
|
|
RSRUK |
| 26 |
| 24 |
| 26 |
| 24 |
|
Equion |
| 16 |
| 21 |
| 14 |
| 17 |
|
|
| 42 |
| 45 |
| 40 |
| 41 |
|
Total daily production from Consolidated Subsidiaries and Joint Ventures (mboe/d) |
| 332 |
| 357 |
| 273 |
| 297 |
|
(1) Other is also referred to as Rest of World.
Production represents gross production before royalties, unless noted otherwise. Production identified as net is production after deducting royalties.
Total daily production for the three months ended March 31, 2017 was 332 mboe/d, a decrease of 7% compared to the same period in 2016. The decrease was primarily due to lower production in Southeast Asia, North America and the Equion joint venture, partially offset by increased production in the RSRUK joint venture and Algeria.
In North America, total production decreased by 6% compared to 2016. Total oil and liquids production decreased by 13%, primarily due to natural declines, partially offset by new wells coming on stream in the US and Canada. Natural gas production decreased by 4% compared to 2016, primarily due to natural declines, partially offset by new wells coming on stream in the US and in the Greater Edson and Duvernay areas of Canada.
In Southeast Asia, total production decreased by 13% compared to 2016. Total oil and liquids production decreased by 22%, primarily due to operational issues and natural declines in Malaysia, natural declines in Vietnam, and the sale of Laminaria-Coralina in Australia/Timore-Leste in April 2016. Natural gas production decreased by 11% compared to 2016, primarily due to the impact of the Talisman Wiriagar Overseas Limited (“TWOL”) divestment in December 2016, lower demand at Corridor in Indonesia and natural declines in Vietnam.
In Rest of World, total production increased by 36% compared to 2016. During the three months ended March 31, 2016, there was a temporary decline in the MLN field’s entitlement to production volumes, principally due to Algeria license extensions that were granted effective January 1, 2016 not being recorded until the third quarter of 2016.
In the RSRUK joint venture, total production increased by 8%, primarily due to production from several fields which were shut down for annual maintenance during the three month period ended March 31, 2016.
Total production in the Equion joint venture decreased by 24%, primarily due to lower natural gas production as a result of a license relinquishment in 2016.
VOLUMES PRODUCED INTO (SOLD OUT OF) INVENTORY1, 2
|
| Three months ended March 31 |
| ||
|
| 2017 |
| 2016 |
|
North America - bbls/d |
| (58 | ) | (2,132 | ) |
Southeast Asia - bbls/d |
| 1,570 |
| 269 |
|
Other - bbls/d |
| (235 | ) | 3,363 |
|
Total produced into inventory - bbls/d |
| 1,277 |
| 1,500 |
|
Total produced into inventory — mmbbls |
| 0.1 |
| 0.1 |
|
Inventory at March 31 — mmbbls |
| 1.1 |
| 1.8 |
|
(1) Gross before royalties.
(2) Amounts shown represent inventory from consolidated subsidiaries and exclude inventory from joint ventures.
The Company’s 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 and liquids volumes produced into inventory and exclude volumes sold out of inventory.
During the three months ended March 31, 2017, volumes in inventory increased from 1.0 mmbbls at December 31, 2016 to 1.1 mmbbls at March 31, 2017 due principally to increased inventories in Malaysia and Vietnam, partially offset by decreased inventories in Indonesia, Colombia and North America.
COMPANY NETBACKS1, 2
|
| Three months ended March 31 |
| ||||||
|
| Gross before royalties |
| Net of royalties |
| ||||
|
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
Oil and liquids ($/bbl) |
|
|
|
|
|
|
|
|
|
Sales price |
| 44.69 |
| 26.34 |
| 44.69 |
| 26.34 |
|
Royalties |
| 13.35 |
| 7.08 |
| — |
| — |
|
Transportation |
| 2.04 |
| 1.79 |
| 2.91 |
| 2.45 |
|
Operating costs |
| 7.64 |
| 8.92 |
| 10.89 |
| 12.19 |
|
|
| 21.66 |
| 8.55 |
| 30.89 |
| 11.70 |
|
Natural gas ($/mcf) |
|
|
|
|
|
|
|
|
|
Sales price |
| 3.88 |
| 2.70 |
| 3.88 |
| 2.70 |
|
Royalties |
| 0.75 |
| 0.49 |
| — |
| — |
|
Transportation |
| 0.17 |
| 0.26 |
| 0.21 |
| 0.32 |
|
Operating costs |
| 0.94 |
| 0.88 |
| 1.17 |
| 1.07 |
|
|
| 2.02 |
| 1.07 |
| 2.50 |
| 1.31 |
|
Total $/boe (5.615 mcf =1boe) |
|
|
|
|
|
|
|
|
|
Sales price |
| 27.67 |
| 18.09 |
| 27.67 |
| 18.09 |
|
Royalties |
| 6.56 |
| 3.87 |
| — |
| — |
|
Transportation |
| 1.22 |
| 1.55 |
| 1.60 |
| 1.97 |
|
Operating costs |
| 5.91 |
| 5.99 |
| 7.35 |
| 7.29 |
|
|
| 13.98 |
| 6.68 |
| 18.72 |
| 8.83 |
|
(1) Netbacks do not include pipeline operations.
(2) Amounts shown represent netbacks from consolidated subsidiaries and exclude netbacks from joint ventures.
During the three months ended March 31, 2017, the Company’s average gross netback was $13.98/boe, 109% higher than in 2016, primarily due to higher realized prices and lower transportation and operating costs, partially offset by higher royalties.
The Company’s realized net price of $27.67/boe for the three months ended March 31, 2017 was 53% higher than 2016, primarily due to higher commodity prices. Oil and liquids and natural gas prices for the three months ended March 31, 2017 increased by 70% and 44% respectively compared to 2016.
The Company’s composite royalty rate was 24% up from 21% in 2016, primarily due to higher commodity prices.
COMMODITY PRICES AND EXCHANGE RATES1
|
| Three months ended March 31 |
| ||
|
| 2017 |
| 2016 |
|
Oil and liquids ($/bbl) |
|
|
|
|
|
North America |
| 32.77 |
| 18.57 |
|
Southeast Asia |
| 55.83 |
| 33.92 |
|
Other |
| 52.62 |
| 31.67 |
|
|
| 44.69 |
| 26.34 |
|
Natural gas ($/mcf) |
|
|
|
|
|
North America |
| 2.80 |
| 1.79 |
|
Southeast Asia |
| 5.76 |
| 4.15 |
|
|
| 3.88 |
| 2.70 |
|
Company $/boe (5.615mcf =1boe) |
| 27.67 |
| 18.09 |
|
Benchmark prices and foreign exchange rates |
|
|
|
|
|
WTI (US$/bbl) |
| 51.91 |
| 33.45 |
|
Dated Brent (US$/bbl) |
| 53.78 |
| 33.89 |
|
WCS (US$/bbl) |
| 37.34 |
| 19.21 |
|
LLS (US$/bbl) |
| 53.51 |
| 35.14 |
|
NYMEX (US$/mmbtu) |
| 3.32 |
| 2.09 |
|
AECO (C$/gj) |
| 2.79 |
| 2.00 |
|
C$/US$ exchange rate |
| 1.32 |
| 1.37 |
|
UK£/US$ exchange rate |
| 0.81 |
| 0.70 |
|
(1) Amounts shown represent commodity prices from consolidated subsidiaries and exclude commodity prices from joint ventures.
In North America, realized oil and liquids prices for the three months ended March 31, 2017 increased 76% compared to 2016, primarily due to increases in benchmark prices. In Southeast Asia, realized oil and liquids prices for the three months ended March 31, 2017 increased 65%, consistent with increases in crude pricing. Accordingly, the Company’s overall realized oil and liquids price for the three months ended March 31, 2017 increased 70% to $44.69/bbl compared to 2016.
In North America, realized natural gas prices for the three months ended March 31, 2017 increased 56% compared to 2016, which is consistent with increases in benchmark prices. In Southeast Asia, where a significant portion of gas sales are linked to oil prices, realized natural gas prices for the three months ended March 31, 2017 increased 39% compared to 2016, which is consistent with increases in benchmark crude pricing. Accordingly, the Company’s overall realized natural gas price for the three months ended March 31, 2017 increased 44% to $3.88/mcf compared to 2016.
EXPENSES
Unit Operating Expenses1
|
| Three months ended March 31 |
| ||||||
|
| Gross before royalties |
| Net of royalties |
| ||||
($/boe) |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
North America |
| 6.14 |
| 5.65 |
| 7.04 |
| 6.41 |
|
Southeast Asia |
| 5.63 |
| 6.22 |
| 7.85 |
| 8.25 |
|
Other |
| 5.29 |
| 8.95 |
| 8.48 |
| 16.33 |
|
|
| 5.91 |
| 5.99 |
| 7.36 |
| 7.29 |
|
(1) Amounts shown represent unit operating expenses from consolidated subsidiaries and exclude unit operating expenses from joint ventures.
Total Operating Expenses1
|
| Three months ended March 31 |
| ||
(millions of $) |
| 2017 |
| 2016 |
|
North America |
| 95 |
| 96 |
|
Southeast Asia |
| 47 |
| 77 |
|
Other |
| 8 |
| 9 |
|
|
| 150 |
| 182 |
|
(1) Amounts shown represent operating expenses from consolidated subsidiaries and exclude operating expenses from joint ventures.
Total operating expenses decreased by 18% to $150 million compared to 2016. Unit operating expense for the three months ended March 31, 2017 decreased marginally to $5.91/boe.
In North America, total operating expenses decreased marginally to $95 million, primarily due to lower workforce costs, offset by a US severance tax recovery in 2016. Unit operating expenses in North America for the three months ended March 31, 2017 increased by 9% compared to 2016 due to lower production.
In Southeast Asia, total operating expenses decreased by 39% to $47 million compared to 2016. The change was primarily due to lower employee related costs and timing of liftings in Malaysia, the sale of Laminaria-Coralina in Australia/Timor-Leste in the second quarter of 2016 and the impact of the TWOL divestment in December 2016 in Indonesia. Unit operating expenses in Southeast Asia decreased by 9% compared to 2016 for the reasons noted above.
In Rest of World, total operating expenses remained relatively consistent compared to 2016 and unit operating expenses decreased by 41% compared to 2016 mainly due to higher production.
Unit Depreciation, Depletion and Amortization (“DD&A”) Expense1
|
| Three months ended March 31 |
| ||||||
|
| Gross before royalties |
| Net of royalties |
| ||||
($/boe) |
| 2017 |
| 2016 |
| 2017 |
| 2016 |
|
North America |
| 15.70 |
| 13.98 |
| 18.02 |
| 15.84 |
|
Southeast Asia |
| 7.44 |
| 6.71 |
| 10.38 |
| 8.90 |
|
Other |
| 10.01 |
| 11.28 |
| 16.02 |
| 20.58 |
|
|
| 12.44 |
| 11.08 |
| 15.49 |
| 13.49 |
|
(1) Amounts shown represent unit DD&A expense from consolidated subsidiaries and exclude unit DD&A expense from joint ventures.
Total DD&A Expense1
|
| Three months ended March 31 |
| ||
(millions of $) |
| 2017 |
| 2016 |
|
North America |
| 241 |
| 231 |
|
Southeast Asia |
| 67 |
| 73 |
|
Other |
| 14 |
| 10 |
|
|
| 322 |
| 314 |
|
(1) Amounts shown represent DD&A expense from consolidated subsidiaries and exclude DD&A expense from joint ventures.
Total DD&A expense for the three months ended March 31, 2017 increased by 3% to $322 million compared to 2016. Unit DD&A expense for the three months ended March 31, 2017 increased by 12% to $12.44/boe.
Total DD&A expense in North America increased by 4% to $241 million compared to 2016, primarily due to higher production and reserve reductions in Duvernay and reserve reductions in Eagle Ford. This was partially offset by lower production and reserve additions in Marcellus. Unit DD&A expense in North America increased by 12% compared to 2016 for the reasons noted above.
Total DD&A expense in Southeast Asia decreased by 8% to $67 million compared to 2016, primarily due to the impact of the TWOL divestment in December 2016 in Indonesia. Unit DD&A expense in Southeast Asia increased by 11% compared to 2016 for the same reasons noted above.
Total DD&A expense in Rest of World increased by 40% to $14 million compared to 2016, primarily due to higher production in Algeria.
Income (Loss) from Joint Ventures1
|
| Three months ended March 31 |
| ||
(millions of $) |
| 2017 |
| 2016 |
|
RSRUK |
| (8 | ) | 20 |
|
Equion |
| 18 |
| (2 | ) |
|
| 10 |
| 18 |
|
(1) Amounts shown represent the Company’s proportionate interest in joint ventures.
RSRUK Joint Venture
The after-tax net loss in RSRUK of $8 million as compared to an after-tax net income of $20 million in 2016 is primarily due to a deferred income tax recovery recorded in 2016 related to petroleum revenue tax (“PRT”) legislation enacted in March 2016 which reduced the PRT rate down to zero. This was partially offset by higher commodity prices, higher oil and liquids production and lower DD&A expense as result of reserve additions in Claymore.
Equion Joint Venture
The after-tax net income in Equion of $18 million for the three months ended March 31, 2017 as compared to an after-tax net loss of $2 million in 2016 is primarily due to higher commodity prices, and lower DD&A expense.
Corporate and Other1
|
| Three months ended March 31 |
| ||
(millions of $) |
| 2017 |
| 2016 |
|
General and administrative expense |
| 54 |
| 63 |
|
Dry hole |
| (4 | ) | 12 |
|
Exploration expense |
| 13 |
| 29 |
|
Finance costs |
| 45 |
| 54 |
|
Gain on disposals |
| (7 | ) | — |
|
Other expenses, net |
| 9 |
| 23 |
|
Other income |
| 17 |
| 47 |
|
(1) Amounts shown represent corporate and other expense from consolidated subsidiaries and exclude corporate and other expense from joint ventures.
G&A expense decreased by $9 million compared to 2016, primarily due lower workforce expenses and reduced reliance on temporary staff and consultants.
In the first quarter of 2017, the dry hole of $4 million primarily related to downward accrual revision relating to a dry hole expense previously recorded in Papua New Guinea.
Exploration expense decreased by $16 million compared to 2016, primarily due to decreased spending in Southeast Asia and Colombia.
Finance costs include interest on long-term debt (including current portion), other finance charges and accretion expense relating to decommissioning liabilities, less interest capitalized. Finance costs decreased by $9 million
compared to 2016, primarily due to the replacement of long-term debt with related party financing, which carries lower financing costs, and lower interest on UK£ debt as a result of the weakening of UK£ against US$.
Other expenses, net of $9 million for the three months ended March 31, 2017 consists primarily of onerous lease contracts and other provisions of $3 million, restructuring costs of $2 million and other miscellaneous expenses of $4 million.
Other income of $17 million for the three months ended March 31, 2017 consists primarily of marketing and other income of $11 million, pipeline and customer treating tariffs of $3 million and investment income of $3 million.
INCOME TAXES1
|
| Three months ended March 31 |
| ||
(millions of $) |
| 2017 |
| 2016 |
|
Loss before taxes |
| (46 | ) | (250 | ) |
Less: PRT |
|
|
|
|
|
Current |
| 2 |
| 2 |
|
Deferred |
| — |
| (4 | ) |
Total PRT |
| 2 |
| (2 | ) |
|
| (48 | ) | (248 | ) |
Income tax expense (recovery) |
|
|
|
|
|
Current income tax expense |
| 62 |
| 38 |
|
Deferred income tax recovery |
| (110 | ) | (141 | ) |
Income tax recovery (excluding PRT) |
| (48 | ) | (103 | ) |
Effective income tax rate (%) |
| 100 | % | 42 | % |
(1) Amounts shown represent income taxes from consolidated subsidiaries and exclude income taxes from joint ventures.
The effective tax rate is expressed as a percentage of income from continuing operations before taxes adjusted for PRT, which is deductible in determining taxable income.
The effective tax rate was impacted by pre-tax income of $123 million in Southeast Asia where tax rates range from 30% to 58% and pre-tax income of $9 million in Rest of World, where tax rates range from 9% to 40%. This was partially offset by pre-tax losses of $97 million in North America, where tax rates are between 27% and 39%, and after-tax loss of $8 million in the RSRUK joint venture.
In addition to the jurisdictional mix of income, the effective tax rate was also impacted by:
· Recognition of a deferred tax asset in Rest of World; and
· Foreign exchange movements on foreign denominated tax pools
For the three months ended March 31, 2017, the current tax expense increased to $62 million compared to $38 million in 2016, due principally to higher revenues in Indonesia and Algeria as a result of increased commodity prices and production.
For the three month ended March 31, 2017, the deferred tax recovery decreased to $110 million from $145 million in 2016, due principally to higher commodity prices in the US, Malaysia and Colombia, the impact of foreign exchange rate changes on tax pools in Malaysia and recognition of a deferred tax asset in Rest of World.
CAPITAL EXPENDITURES
|
| Three months ended March 31 |
| ||
(millions of $) |
| 2017 |
| 2016 |
|
North America |
| 116 |
| 137 |
|
Southeast Asia |
| 20 |
| 21 |
|
Other |
| 8 |
| 3 |
|
Exploration and development expenditure from Consolidated Subsidiaries1 |
| 144 |
| 161 |
|
Corporate and other |
| 1 |
| 1 |
|
Proceeds of dispositions |
| (2 | ) | — |
|
Net capital expenditure for Consolidated Subsidiaries |
| 143 |
| 162 |
|
RSRUK |
| 34 |
| 47 |
|
Equion |
| 4 |
| 5 |
|
Exploration and development expenditure from Joint Ventures2 |
| 38 |
| 52 |
|
Net capital expenditure for Consolidated Subsidiaries and Joint Ventures |
| 181 |
| 214 |
|
(1) Excludes $13 million exploration expense for the three months ended March 31, 2017, ($29 million - three months ended March 31, 2016).
(2) Represents the Company’s proportionate interest, excluding exploration expense $nil for the three months ended March 31, 2017, ($1 million net - three months ended March 31, 2016).
In North America, capital expenditures for the three months ended March 31, 2017 were $116 million, a decrease of 15% from 2016. Approximately $91 million related to development activity, with the majority spent in the Marcellus, Eagle Ford, and Greater Edson areas. The remaining capital expenditures were invested in exploration activities, largely in the Duvernay area of Canada.
In Southeast Asia, capital expenditures for the three months ended March 31, 2017 were $20 million, including approximately $18 million on development activity, with the majority spent in Indonesia and Malaysia. The remaining capital expenditures were invested in exploration activities, largely in Indonesia and Vietnam.
In Rest of World, capital expenditures for the three months ended March 31, 2017 were $8 million, with approximately $5 million spent on development activities in Algeria and the majority of the remainder spent on exploration activities in Colombia.
In the RSRUK joint venture, capital expenditures of $34 million consisted primarily of development activities relating to the Monarb Area Redevelopment project. In the Equion joint venture, net capital expenditures of $4 million related primarily to activities in Piedemonte.
LIQUIDITY AND CAPITAL RESOURCES
The Company’s gross debt and loans from related parties at March 31, 2017 was $3.2 billion compared to $3.1 billion at December 31, 2016. During the three months ended March 31, 2017, the Company generated $221 million cash from operating activities, incurred capital expenditures of $147 million, and drew loans from related
parties of $34 million.
The Company’s capital structure consists of shareholder’s equity and debt from capital markets and related parties. The Company makes adjustments to its capital structure based on changes in economic conditions and its planned requirements. The Company has the ability to adjust its capital structure by issuing new equity or debt, selling assets to reduce debt, controlling the amount it returns to its shareholder and making adjustments to its capital expenditure program.
The Company monitors its balance sheet with reference to its liquidity. The main factors in assessing the Company’s liquidity are cash flow, including cash flow from joint ventures, cash provided by and used in investing activities and available related party facilities. The Company manages its liquidity requirements by use of both short-term and long-term cash forecasts, and by maintaining appropriate undrawn capacity under related party credit facilities. The Company has entered into three revolving facilities with subsidiaries of its ultimate parent, Repsol, with total borrowing limit of $3.5 billion. As at March 31, 2017, $1.8 billion drawings were outstanding under these facilities. In May 2017, amendments were made to the facility agreements - see ‘TRANSACTIONS WITH RELATED PARTIES”. There were also $108 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.
In addition, the Company utilizes letters of credit pursuant to letter of credit facilities, all of which are uncommitted. At March 31, 2017, the Company had $97 million letters of credit outstanding, primarily related to a retirement compensation arrangement, guarantees of minimum work commitments and decommissioning obligations.
The obligation to fund RSRUK, in proportion to its shareholding, continues to be in line with the Company’s practice of funding RSRUK’s cash flow deficiencies. The Company’s obligation to fund RSRUK will increase to the extent future losses are generated within RSRUK. In addition, future contributions to the RSRUK joint venture could be impaired to the extent recoverability is not probable.
At March 31, 2017, the Company’s share of RSRUK’s total recorded decommissioning liabilities was $2.6 billion, corresponding to the Company’s 51% participating interest.
RSRUK is required to provide letters of credit as security in relation to certain decommissioning obligations in the UK pursuant to contractual arrangements under DSAs. With the exception of two DSAs which are still required to be negotiated, security posted is on an after-tax basis, following UK legislation passed in 2013 which provides for the government to guarantee tax relief on decommissioning costs at 50%. As at March 31, 2017, RSRUK’s tax relief guaranteed by the UK government is capped at $1.5 billion, equivalent to RSRUK’s corporate tax paid and recoverable since 2002. At March 31, 2017, RSRUK has $2.7 billion of demand shared facilities in place under which letters of credit of $1.3 billion have been issued. The Company and Repsol guaranteed $120 million and $523 million, respectively, demand letters of credit issued under RSRUK’s uncommitted facilities, primarily as security for the costs of decommissioning obligations in the UK. The remaining demand letters of credit of $115 million were guaranteed by Addax and $503 million were secured by letters of credit issued by Addax’s banks.
The Company has also granted guarantees to various beneficiaries in respect of decommissioning obligations of
RSRUK. Any changes to decommissioning estimates influence the value of letters of credit required to be provided pursuant to DSAs. In addition, the extent to which shared facility capacity is available, and the cost of that capacity, is influenced by the Company and Repsol’s investment-grade credit rating.
During 2016, the Company granted a guarantee of UK£46 million in respect of RSRUK’s pension scheme liabilities.
The Company is exposed to credit risk, which is the risk that a customer or counterparty will fail to perform an obligation or settle a liability, resulting in financial loss to the Company. The Company manages exposure to credit risk by adopting credit risk guidelines approved by the Board of Directors that limit transactions according to counterparty creditworthiness. The Company routinely assesses the financial strength of its joint participants and customers, in accordance with the credit risk guidelines. The Company’s credit policy requires collateral to be obtained from counterparties considered to present a material risk of non-payment, which would include entities internally assessed as high risk. A significant proportion of the Company’s accounts receivable balance is with customers in the oil and gas industry and is subject to normal industry credit risks. At March 31, 2017, approximately 91% of the Company’s trade accounts receivable was current. The largest single counterparty exposure, accounting for 7% of the total accounts receivable, was with a highly rated counterparty. Concentration of counterparty credit risk is managed by having a broad domestic and international customer base primarily of highly rated counterparties. In addition, 16% of the Company’s accounts receivable was with subsidiaries of the Company’s ultimate parent, Repsol, as a result of the related party transactions - see ‘TRANSACTIONS WITH RELATED PARTIES”.
There were 1,834,375,452 common shares outstanding at March 31, 2017. On April 18, 2017 Repsol Energy Resources Canada, Inc. (“RERCI”), a subsidiary of the Company’s ultimate parent Repsol, subscribed for $1.5 billion in the Company’s common shares (786,125,654 common shares at $1.91 per share), which settled $1.5 billion of the balance owing from the Company to RERCI under the revolving facility. On May 12, 2017 there were 2,620,501,106 common shares outstanding.
For additional information regarding the Company’s liquidity and capital resources, refer to notes 11, 13 and 14 to the Company’s unaudited condensed Consolidated Financial Statements as at and for the three months ended March 31, 2017 and notes 17, 19 and 21 to the Company’s 2016 audited Restated Consolidated Financial Statements.
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 2016 audited Restated Consolidated Financial Statements. 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 decommissioning liabilities, debt repayment obligations and significant commitments can be found in notes 8, 15, 17, 18 and 22 to the 2016 audited Restated Consolidated Financial Statements.
During the three months ended, March 31, 2017, there have been no significant changes in the Company’s expected future commitments, and the timing of those payments.
TRANSACTIONS WITH RELATED PARTIES
Repsol
The nature and scope of related party transactions could increase in future periods as integration activities with Repsol continue. Specifically, further asset transactions may occur. The Company has entered into three revolving facilities with subsidiaries of its ultimate parent, Repsol, with total borrowing limit of $3.5 billion.
TE Holding SARL. (“TEHS”), a subsidiary of the Company, entered into a $500 million revolving facility with Repsol Tesoreria y Gestion Financiera, S.A. (“RTYGF”), a subsidiary of Repsol. The facility matures on May 8, 2018 and bears an interest rate of LIBOR (1 month) plus 1.20%. At March 31, 2017, $225 million was outstanding under this facility (December 31, 2016 - $261 million). Interest expense related to the facility recognized by the Company during the three months ended March 31, 2017 was $1 million. In May 2017, the facility agreement was modified to extend the maturity date to May 8, 2020.
The Company entered into a $2.8 billion revolving facility with RERCI. The facility matures on May 8, 2018 and bears an interest rate of LIBOR (1 month) plus 1.20%. At March 31, 2017, $1.6 billion was outstanding under this facility (December 31, 2016 - $1.5 billion). Interest expense related to the facility recognized by the Company during the three months ended March 31, 2017 was $8 million. In May 2017, the facility agreement was modified to extend the maturity date to May 8, 2020.
ROGUSA, ( formerly Talisman Energy USA Inc. or “TEUSA”), a subsidiary of the Company, entered into a $125 million revolving facility with Repsol USA Holdings Corporation (“RUSA”), a subsidiary of Repsol. The facility matures on June 8, 2017 and bears an interest rate of LIBOR (6 month) plus 1.70%. ROGUSA also provides RUSA an $85 million supplementary revolving facility, with interest rate of LIBOR (1 month). At March 31, 2017 and December 31, 2016, there were no drawings outstanding under the primary facility. Instead, RUSA had a balance of $83 million payable to ROGUSA under the supplemental facility (December 31, 2016 - $67 million). Interest income related to the facility recognized by the Company during the three months ended March 31, 2017 was less than $1 million.
As at March 31, 2017, there were $108 million letters of credit issued under Repsol’s facilities on behalf of the Company’s subsidiaries.
North America
In connection with the sale of 20% of the interest in ROGUSA, Repsol E&P USA Holdings Inc., an indirect subsidiary of the Company, entered into a $502 million loan agreement effective December 31, 2016 with RUSA. The loan receivable matures on June 30, 2017 and bears an interest rate of LIBOR (1 month). As at March 31, 2017, RUSA had a balance of $503 million payable to Repsol E&P USA Holdings Inc. In April 2017, the loan receivable balance from RUSA was amended to $442 million to reflect the final purchase price of 20% interest of ROGUSA. Interest income related to the loan during the three months ended March 31, 2017 was $1 million.
During the three months ended March 31, 2017, Repsol Canada Energy Partnership sold to Repsol Energy Canada Limited, a subsidiary of Repsol, approximately 19 trillion btu of natural gas for $40 million. As at March 31, 2017, the amount included in accounts receivable as a result of these transactions was $13 million.
During the three months ended March 31, 2017, ROGUSA sold to Repsol Energy North America Corporation, a subsidiary of Repsol, approximately 32 trillion btu of natural gas for $97 million and additional transport capacity income of $5 million. As at March 31, 2017, the amount included in accounts receivable as a result of these transactions was $30 million.
Southeast Asia
The Company entered into a commitment in 2001, along with its Corridor block partners and parties from two other blocks, to sell gas to Gas Supply Pte. Ltd (“GSPL”), a subsidiary of Repsol’s significant shareholder Temasek Holdings (Private) Limited (“Temasek”). Currently, ROGCI’s share of the sale on a daily basis is approximately 75 billion btu. The commitment matures in 2023. During the three months ended March 31, 2017, the Company’s gas sales to GSPL totaled $33 million (net of royalties and the Company’s share). As at March 31, 2017, the amount included in accounts receivable as a result of this commitment was $27 million.
Rest of World
During the three months ended March 31, 2017, Talisman (Algeria) B.V., a subsidiary of the Company, sold to Repsol Trading S.A., a subsidiary of Repsol, approximately 0.5 million barrels of Saharan Blend Crude Oil for $27 million. As at March 31, 2017, the amount included in accounts receivable as a result of these transactions was $17 million.
RSRUK
On July 1, 2015, to fund capital, decommissioning and operating expenditures of RSRUK, the shareholders of RSRUK provided an equity funding facility of $1.7 billion, of which the Company is committed to $867 million with a maturity date of December 31, 2017. During the three months ended March 31, 2017, the shareholders of RSRUK agreed to subscribe for common shares of RSRUK in the amount of $45 million under this facility, of which the Company’s share was $23 million.
The shareholders of RSRUK have provided an unsecured loan facility totaling $2.4 billion to RSRUK, of which the Company is committed to $1.2 billion, for the purpose of funding capital expenditures of RSRUK. There was no loan balance outstanding as at March 31, 2017. The remaining borrowing capacity under this facility was $742 million ($378 million net to the Company’s share).
Equion
The Company has a loan due to Equion of $39 million (December 31, 2016 - $10 million) which is unsecured, due upon demand and bears interest at LIBOR plus 0.30%.
RISK MANAGEMENT
In addition to the risks discussed in the “LIQUIDITY AND CAPITAL RESOURCES” section of this MD&A, the Company monitors its exposure to variations in commodity prices, interest rates and foreign exchange rates. In response, the Company 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.
The accounting policy with respect to derivative financial instruments and commodity sales contracts is set out in note 4(q) to the Company’s 2016 audited Restated Consolidated Financial Statements.
The Company had elected not to designate as hedges for accounting purposes any derivative contracts entered into. 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 quarterly. This can potentially increase the volatility of net income.
Following Repsol’s acquisition of the Company in 2015, the Company liquidated substantially all of its contracts related to commodity price risk management. The Company has not entered into any new commodity price risk management derivative contracts subsequently.
USE OF ESTIMATES AND JUDGMENTS
The preparation of the unaudited condensed Consolidated Financial Statements as at and for the three months ended March 31, 2017 requires management to make assumptions and estimates that affect the valuation of the amounts of assets and liabilities recognized, the income and expenses reported during the period and the presentation of contingent assets and liabilities. Management is also required to adopt accounting policies that require the use of significant estimates and judgment. Actual results may differ from estimated amounts. Judgments and estimates are reviewed by management on a regular basis. There has been no significant change in the critical accounting estimates underlying the accounting policies applied in the preparation of the unaudited condensed Consolidated Financial Statements since the year ended December 31, 2016.
SIGNIFICANT ACCOUNTING POLICIES
The unaudited condensed Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the Company’s 2016 audited Restated Consolidated Financial Statements, except for the adoption of amendments to IAS 7 Statement of Cash Flows and amendments to IAS 12 Income Taxes, as disclosed in note 4 of the 2016 audited Restated Consolidated Financial Statements.
INTERNAL CONTROL OVER FINANCIAL REPORTING (“ICFR”)
Subsequent to December 31, 2016, management determined that a related party transaction resulting in a non-controlling interest was not accounted for correctly as described in the Restatement of Previously Issued Financial Statements section of the Restated MD&A for the year ended December 31, 2016.
This resulted in a review by management during the three months ended March 31, 2017, which indicated a material weakness in the Company’s ICFR for the year ended December 31, 2016 relating to the review of the accounting treatment of this non-controlling interest transaction. Through analysis, management concluded that the material weakness of the Company’s ICFR for the year ended December 31, 2016 was isolated to the above non-controlling interest transaction. Management’s review and conclusions were discussed with the Audit Committee.
During the three months ended March 31, 2017, the Company has not entered into similar transactions.
Changes Due to Remediation of Material Weakness in ICFR
Subsequent to December 31, 2016, management has implemented appropriate remedial actions to address the material weakness identified in the Company’s restated December 31, 2016 ICFR assessment. The remediation includes the strengthening of specific controls over the analysis and review of the impact in the financial statements of significant non-routine transactions, including non-controlling interest transactions. These measures will reinforce the responsibilities for review by individuals with specialized knowledge.
Those remediation activities implemented in respect of such material weakness constitute a material change in the Company’s ICFR.
Management has discussed the remedial actions taken to address the material weakness with the Audit Committee and the Board.
During the three months ended March 31, 2017, the integration activities with the Company’s ultimate parent, Repsol continued with certain ROGCI policies being replaced by Repsol SA global policies, which have not materially affected the Company’s ICFR.
LEGAL PROCEEDINGS
From time to time, the Company is the subject of litigation arising out of the Company’s operations. Damages claimed under such litigation, including the litigation discussed below 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 the Company 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. None of these claims are currently expected to have a material impact on the Company’s financial position. A summary of specific legal proceedings and contingencies are as follows:
In August 2012, a portion of the Galley pipeline, in which RSRUK has a 67.41% interest, suffered an upheaval buckle. In September 2012, RSRUK submitted a notification of a claim to Oleum Insurance Company (‘‘Oleum’’), a wholly-owned subsidiary of the Company. RSRUK delivered a proof of loss seeking recovery under the insuring agreement of $350 million. To date, the documentation delivered by RSRUK purporting to substantiate its claim does not support coverage. On August 8, 2016, RSRUK served its Request for Arbitration and on September 7, 2016, Oleum served its response. The seat of the arbitration is London, while the law of New York governs the claim for damages and business interruption. The arbitration is currently in the pleadings stage, after which the tribunal will decide on the trial dates, among other procedural matters.
On July 13, 2015, Addax and Sinopec International Petroleum Exploration and Production Corporation (“Sinopec”), filed a “Notice of Arbitration” against ROGCI and Talisman Colombia Holdco Limited (“TCHL”) in connection with the purchase of 49% shares of RSRUK. ROGCI and TCHL filed their response to the Notice of Arbitration on October 1, 2015. On May 25, 2016, Addax and Sinopec filed the Statement of Claim, in which they seek, in the event that their claims were confirmed in their entirety, repayment of their initial investment in RSRUK, which was executed in 2012 through the purchase of 49% of RSRUK from TCHL, a wholly-owned subsidiary of ROGCI, together with any additional investment, past or future, in such company, and further for any loss of opportunity, which they estimate in a total approximate amount of $5.5 billion. The Arbitral Tribunal has decided, among other procedural matters, the bifurcation of the proceedings; the hearing related to liability issues has been scheduled for January 29 to February 20, 2018, and, if necessary, the hearing related to damages will take place at a later date still undecided, although it is likely to be fixed for the beginning of 2019. The Company maintains its opinion that the claims included in the Statement of Claim are without merit.
During 2016, the Alberta Energy Regulator (“AER”) informed the Company that certain permits to construct well sites and access roads were obtained without the Company following proper procedures. The Company has worked closely with the AER to close this matter. At this time, the company does not expect any enforcement actions that the AER may issue to have a material impact on the Company’s operations.
Government and Legal Proceedings with Tax Implications
Specific tax claims which the Company and its subsidiaries are parties to at December 31, 2016 are as follows:
Canada
Pursuant to administrative proceedings by the Canada Revenue Agency (“CRA”) on the situation of the ROGCI Group of companies based in Canada for the years 2006-2010, a Notice of Reassessment resulting in adjustments to the 2006 tax return under several items was received. The Company does not expect this claim to have a significant impact for the Group. The Company will file the appropriate appeals as it considers some of the item adjustments to be incorrect.
Indonesia
Indonesian Corporate Tax Authorities have been questioning various aspects of the taxation of permanent establishments that ROGCI subsidiaries have in the country. These proceedings are pending a court decision.
Malaysia
The Company’s branches in Malaysia of Repsol Oil & Gas Malaysia Limited, formerly Talisman Malaysia Ltd. and Repsol Oil & Gas Malaysia (PM3) Limited, formerly Talisman Malaysia (PM3) Ltd., had received notifications of additional assessment from the Inland Revenue Board in respect of the years of assessment 2007, 2008 and 2011, disallowing the deduction of certain costs. The appeal was submitted to the Special Commissioners of Petroleum Income Tax (“SCPIT”). Currently the Dispute Resolution Panel of the SCPIT is working with the Company’s external legal consultants for an out of court settlement while the case is waiting to be heard.
Timor-Leste
With respect to administrative proceedings by the authorities of Timor-Leste on the deductibility of certain expenses in income tax by Repsol Oil & Gas Australia (JPDA 06-105) Pty Limited, the authorities have recently withdrawn the pre-assessment questioning.
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;
· expected capital expenditures, timing and planned focus of such spending;
· the estimated impact on the Company’s financial performance from changes in production volumes, commodity prices and exchange rates;
· expected sources of capital to fund the Company’s capital program
· anticipated funding of the decommissioning liabilities;
· anticipated timing and results of legal proceedings;
· other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future events, conditions, results of operations or performance; and
· potential future related party transactions and asset transactions
The factors or assumptions on which the forward-looking information is based include: 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; the 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 2017 assumes escalating commodity prices.
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 the Company and described in the forward-looking information contained in this MD&A.
The material risk factors include, but are not limited to:
· fluctuations in oil and gas prices, foreign currency exchange rates, interest rates and tax or royalty rates;
· 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;
· 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);
· uncertainties related to the UK’s vote in favour of leaving the European Union;
· risks related to cybersecurity;
· 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 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 or strategy are included in the Company’s most recent AIF. 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.
Use of “boe”
Throughout this MD&A, the calculation of barrels of oil equivalent (boe) is calculated at a conversion rate of five thousand six hundred fifteen cubic feet (mcf) of natural gas to one barrel (bbl) 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 5.615 mcf: 1bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent value equivalence at the wellhead.
Oil and Gas Information
Throughout this MD&A, the Company 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. The Company discloses netbacks in this MD&A. Netbacks per boe are calculated by deducting from sales price associated royalties, operating and transportation costs.
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 |
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|
boe | barrels of oil equivalent |
|
|
boe/d | barrels of oil equivalent per day |
|
|
btu | British terminal units |
|
|
C$ | Canadian dollar |
|
|
DSA | Decommissioning Security Agreements |
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|
G&A | General and administrative |
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LIBOR | London Interbank Offered Rate |
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LLS | Light Louisiana Sweet |
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mbbls/d | thousand barrels per day |
|
|
mboe/d | thousand barrels of oil equivalent per day |
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|
mcf | thousand cubic feet |
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|
mcf/d | thousand cubic feet per day |
|
|
mmbbls | million barrels |
|
|
mmbtu | million British thermal units |
mmcf/d | million cubic feet per day |
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NYMEX | New York Mercantile Exchange |
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PP&E | Property, plant and equipment |
|
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PRT | Petroleum Revenue Tax |
|
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SEC | US Securities and Exchange Commission |
|
|
UK | United Kingdom |
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UK£ | Pound sterling |
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US | United States of America |
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US$ or $ | United States dollar |
|
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WCS | Western Canadian Select |
|
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WTI | West Texas Intermediate |
Gross production mean the Company’s interest in production volumes (through working interests and royalty interests) before the deduction of royalties.
Net production means the Company’s interest in production volumes after deduction of royalties payable by the Company.
Gross wells mean 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 acre |
| = 0.40 hectares |
1 barrel |
| = 0.159 cubic metres |
1 cubic foot |
| = 0.0282 cubic metres |
REPSOL OIL & GAS CANADA INC.
Suite 2000, 888 – 3rd Street SW
Calgary, Alberta, Canada T2P 5C5
P 403.237.1234 F 403.237.1902
E infocanada@repsol.com
www.repsol.com/ca_en/