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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Vermilion Energy Inc | TSX:VET | Toronto | Common Stock |
Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|---|---|
-0.05 | -0.32% | 15.40 | 15.40 | 15.41 | 15.45 | 15.28 | 15.33 | 105,219 | 15:32:22 |
CALGARY, Aug. 10, 2015 /PRNewswire/ - Vermilion Energy Inc. ("Vermilion", "We", "Our", "Us" or the "Company") (TSX, NYSE: VET) is pleased to report operating and unaudited financial results for the three and six months ended June 30, 2015.
HIGHLIGHTS
(1) | Additional GAAP Financial Measure. Please see the "Additional and Non-GAAP Financial Measures" section of Management's Discussion and Analysis. |
(2) | Slootdorp-06 (Slochteren) production test was performed over an 18-day period at a maximum choke of 64/64" with approximately 45% drawdown over the test period. Slootdorp-07 (lower zone - Z2) production test was performed over a 4-hour test period at a maximum choke of 36/64" with approximately 35% drawdown over the test period. Slootdorp-07 (upper zone - Z3) production test was performed over a 12-hour test period at a maximum choke of 16/64" with approximately 40% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery. |
(3) | Corrib P2 well produces from the Sherwood sandstones. The production test was performed over a 12-hour period at a maximum choke of 80/64", achieving a peak production rate of 113 mmcf/d and a stabilized flow rate of 107 mmcf/d with approximately 30% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery. |
Conference Call and Audio Webcast Details
Vermilion will discuss these results in a conference call to be held on Monday, August 10, 2015 at 9:00 AM MST (11:00 AM EST). To participate, you may call 1-888-231-8191 (Canada and US Toll Free) or 1-647-427-7450 (International and Toronto Area). The conference call will also be available on replay by calling 1-855-859-2056 using conference ID number 61285178. The replay will be available until midnight mountain time on August 17, 2015.
You may also listen to the audio webcast by going to http://event.on24.com/r.htm?e=1008324&s=1&k=F4CB45E944014BE7D369F641D1A3B805 or visit Vermilion's website at www.vermilionenergy.com/ir/eventspresentations.cfm.
HIGHLIGHTS | ||||||||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
($M except as indicated) | Jun 30, | Mar 31, | Jun 30, | Jun 30, | Jun 30, | |||||||||||
Financial | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||||
Petroleum and natural gas sales | 264,331 | 195,885 | 387,684 | 460,216 | 768,867 | |||||||||||
Fund flows from operations (1) | 129,496 | 120,795 | 216,076 | 250,291 | 421,439 | |||||||||||
Fund flows from operations ($/basic share) | 1.18 | 1.12 | 2.05 | 2.31 | 4.05 | |||||||||||
Fund flows from operations ($/diluted share) | 1.17 | 1.11 | 2.01 | 2.28 | 3.99 | |||||||||||
Net earnings | 6,813 | 1,275 | 53,993 | 8,088 | 156,781 | |||||||||||
Net earnings ($/basic share) | 0.06 | 0.01 | 0.51 | 0.07 | 1.51 | |||||||||||
Capital expenditures | 90,173 | 174,311 | 135,073 | 264,484 | 331,448 | |||||||||||
Acquisitions | 480 | 35 | 381,139 | 515 | 559,366 | |||||||||||
Asset retirement obligations settled | 1,218 | 3,107 | 2,381 | 4,325 | 5,032 | |||||||||||
Cash dividends ($/share) | 0.645 | 0.645 | 0.645 | 1.290 | 1.290 | |||||||||||
Dividends declared | 70,976 | 69,390 | 68,710 | 140,366 | 134,717 | |||||||||||
% of fund flows from operations | 55% | 57% | 32% | 56% | 32% | |||||||||||
Net dividends (1) | 28,675 | 48,012 | 49,561 | 76,687 | 96,683 | |||||||||||
% of fund flows from operations | 22% | 40% | 23% | 31% | 23% | |||||||||||
Payout (1) | 120,066 | 225,430 | 187,015 | 345,496 | 433,163 | |||||||||||
% of fund flows from operations | 93% | 187% | 87% | 138% | 103% | |||||||||||
% of fund flows from operations (excluding the Corrib project) | 76% | 173% | 73% | 123% | 92% | |||||||||||
Net debt (1) | 1,377,902 | 1,388,603 | 1,168,998 | 1,377,902 | 1,168,998 | |||||||||||
Ratio of net debt to annualized fund flows from operations (1) | 2.7 | 2.9 | 1.4 | 2.8 | 1.4 | |||||||||||
Operational | ||||||||||||||||
Production | ||||||||||||||||
Crude oil (bbls/d) | 28,916 | 28,181 | 30,184 | 28,550 | 28,759 | |||||||||||
NGLs (bbls/d) | 3,867 | 3,039 | 2,892 | 3,455 | 2,518 | |||||||||||
Natural gas (mmcf/d) | 114.29 | 115.00 | 114.08 | 114.64 | 108.73 | |||||||||||
Total (boe/d) | 51,831 | 50,386 | 52,089 | 51,113 | 49,398 | |||||||||||
Average realized prices | ||||||||||||||||
Crude oil and NGLs ($/bbl) | 68.90 | 58.25 | 109.89 | 64.23 | 110.73 | |||||||||||
Natural gas ($/mcf) | 4.86 | 5.26 | 6.19 | 5.06 | 7.04 | |||||||||||
Production mix (% of production) | ||||||||||||||||
% priced with reference to WTI | 27% | 28% | 30% | 27% | 27% | |||||||||||
% priced with reference to AECO | 21% | 20% | 18% | 21% | 18% | |||||||||||
% priced with reference to TTF | 16% | 18% | 18% | 17% | 19% | |||||||||||
% priced with reference to Dated Brent | 36% | 34% | 34% | 35% | 36% | |||||||||||
Netbacks ($/boe) (1) | ||||||||||||||||
Operating netback | 36.89 | 31.30 | 59.52 | 34.30 | 61.29 | |||||||||||
Fund flows from operations netback | 26.76 | 29.07 | 46.24 | 27.83 | 46.98 | |||||||||||
Operating expenses | 12.12 | 10.56 | 12.46 | 11.40 | 12.95 | |||||||||||
Average reference prices | ||||||||||||||||
WTI (US $/bbl) | 57.94 | 48.63 | 102.99 | 53.29 | 100.84 | |||||||||||
Edmonton Sweet index (US $/bbl) | 55.08 | 41.83 | 96.85 | 48.46 | 93.65 | |||||||||||
Dated Brent (US $/bbl) | 61.92 | 53.97 | 109.63 | 57.95 | 108.93 | |||||||||||
AECO ($/GJ) | 2.52 | 2.60 | 4.44 | 2.56 | 4.93 | |||||||||||
TTF ($/GJ) | 7.94 | 8.25 | 7.91 | 8.10 | 9.02 | |||||||||||
Average foreign currency exchange rates | ||||||||||||||||
CDN $/US $ | 1.23 | 1.24 | 1.09 | 1.24 | 1.10 | |||||||||||
CDN $/Euro | 1.36 | 1.40 | 1.50 | 1.38 | 1.50 | |||||||||||
Share information ('000s) | ||||||||||||||||
Shares outstanding - basic | 109,806 | 107,718 | 106,620 | 109,806 | 106,620 | |||||||||||
Shares outstanding - diluted(1) | 112,626 | 110,761 | 109,371 | 112,626 | 109,371 | |||||||||||
Weighted average shares outstanding - basic | 109,319 | 107,513 | 105,577 | 108,421 | 103,936 | |||||||||||
Weighted average shares outstanding - diluted | 110,746 | 109,305 | 107,330 | 109,792 | 105,531 |
(1) |
The above table includes additional GAAP and non-GAAP financial measures
which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
DISCLAIMER
Certain statements included or incorporated by reference in this document may constitute forward looking statements or financial outlooks under applicable securities legislation. Such forward looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information in this document may include, but are not limited to: capital expenditures; business strategies and objectives; operational and financial performance; estimated reserve quantities and the discounted present value of future net cash flows from such reserves; petroleum and natural gas sales; future production levels (including the timing thereof) and rates of average annual production growth; estimated contingent resources and prospective resources; exploration and development plans; acquisition and disposition plans and the timing thereof; operating and other expenses, including the payment and amount of future dividends; royalty and income tax rates; the timing of regulatory proceedings and approvals; and the timing of first commercial natural gas and the estimate of Vermilion's share of the expected natural gas production from the Corrib field.
Such forward looking statements or information are based on a number of assumptions all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions have been made regarding, among other things: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids and natural gas prices; and management's expectations relating to the timing and results of exploration and development activities.
Although Vermilion believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives and the information may not be appropriate for other purposes. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward looking statements or information. These risks and uncertainties include but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids and natural gas prices, foreign currency exchange rates and interest rates; health, safety and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future law suits and regulatory actions against Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities.
The forward looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws.
All oil and natural gas reserve information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of crude oil and natural gas reserves does not represent the fair market value of these reserves.
Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
ABBREVIATIONS
$M | thousand dollars | ||
$MM | million dollars | ||
AECO | the daily average benchmark price for natural gas at the AECO 'C' hub in southeast Alberta | ||
bbl(s) | barrel(s) | ||
bbls/d | barrels per day | ||
bcf | billion cubic feet | ||
boe |
barrel of oil equivalent, including: crude oil, natural gas liquids and natural gas (converted on the basis of one boe for six mcf of natural gas) | ||
boe/d | barrel of oil equivalent per day | ||
GJ | gigajoules | ||
HH | Henry Hub, a reference price paid for natural gas in US dollars at Erath, Louisiana | ||
mbbls | thousand barrels | ||
mboe | thousand barrel of oil equivalent | ||
mcf | thousand cubic feet | ||
mcf/d | thousand cubic feet per day | ||
mmboe | million barrel of oil equivalent | ||
mmcf | million cubic feet | ||
mmcf/d | million cubic feet per day | ||
MWh | megawatt hour | ||
NGLs | natural gas liquids | ||
NGTL | NOVA Gas Transmission Ltd., a wholly owned subsidiary of TransCanada is the owner of a gas transmission system known as the NGTL system. The NGTL system is a 23,500 km pipeline that gathers natural gas for both use in Alberta, and to deliver it to provincial border points for export to North American markets. | ||
PRRT | Petroleum Resource Rent Tax, a profit based tax levied on petroleum projects in Australia | ||
TTF |
the day-ahead price for natural gas in the Netherlands, quoted in MWh of natural gas, at the Title Transfer Facility Virtual Trading Point operated by Dutch TSO Gas Transport Services | ||
WTI | West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma |
MESSAGE TO SHAREHOLDERS
After appearing to reach some degree of range-bound stability during the second quarter, crude oil prices have recently come under renewed pressure as a result of a number of macroeconomic uncertainties. Although this price environment poses significant challenges for many energy sector participants, Vermilion remains comparatively well-positioned given our disciplined approach to financial management and our commodity diversification. In particular, our exposure to European natural gas markets, where fundamentals and pricing remain strong, is a key advantage differentiating Vermilion from its competitors.
As current European natural gas prices remain nearly triple those in Canada, a significant part of our strategic focus has been on maximizing our exposure to this advantageously priced commodity. In 2014, we expanded our European natural gas production by nearly 50% with our entry into Germany, a producing region with a long history of development activity and strong market fundamentals. As detailed later in this Message (see German Farm-In), we have further expanded our European natural gas opportunities by entering into an 850,000 acre farm-in in the key German producing basin. In addition, we have received a conditional award for a 2.35 million acre position in the underexploited Croatian portion of the Pannonian basin (see Croatian Exploration Block Award). With continued organic growth in Netherlands natural gas production, combined with forthcoming natural gas production from our Corrib project in Ireland, European natural gas will continue to increase in prominence for Vermilion.
Our international diversification and associated exposure to Brent-based crude oil pricing continues to favorably distinguish us from our North America-focused competitors. This advantage is illustrated by the second quarter's operating netback for our Brent-based crude oil sales in Australia and France, which was a blended $51.89/boe, as compared to the operating netback of $48.41/boe for our WTI-based crude oil sales in North America.
In February 2015, we announced a reduction in our 2015 exploration and development ("E&D") capital program to $415 million in response to the significant decrease in crude oil prices that began in mid-2014. Following a comprehensive review of our E&D capital opportunities, we have elected to increase our 2015 E&D capital program to $485 million, an increase of $70 million from our previous capital guidance of $415 million (but less than our original 2015 E&D capital budget of $525 million and 2014 E&D capital expenditures of $688 million). The majority of this increase is associated with the reinstatement of a two-well Australia sidetrack program. The strong economics of this program, coupled with current services pricing advantages and operational efficiencies associated with drilling the wells outside of cyclone season, support our decision to proceed with this project. Vermilion also intends to drill and complete two additional (1.8 net) Mannville condensate-rich natural gas wells and tie-in a third Mannville well. Modest incremental funding has been made available for additional highly economic workovers in France and Canada, and the revised capital program also reflects a minor increase in capital for Ireland as we ramp up for first gas production. We remain on target to achieve our original full year 2015 production guidance of 55,000 to 57,000 boe/d. Based on a mid-fourth quarter start-up for Corrib natural gas production and only modest production contributions in 2015 from our incremental capital, we consider it more likely that annual production will come in closer to the lower end of our guidance range. This would still represent year-over-year production growth exceeding 10%, supported by consolidated organic production growth in each successive quarter of 2015.
In late 2014, we initiated a Profitability Enhancement Program ("PEP") to systematically identify cost savings and efficiency opportunities company-wide. Prior installments of PEP achieved strong results in both the 1998 industry downturn and the financial crisis of 2008-2009. Based on savings identified to-date, this iteration of PEP is expected to result in cost savings related to capital spending, operating expense and G&A estimated at between $60 and $70 million for full-year 2015.
Results from our European development activities have exceeded our expectations. In late April, we started production from the four (4.0 net) wells we drilled in the Champotran field in the Paris Basin in France in Q1 2015. These wells contributed approximately 800 boe/d to our second quarter average production rate, and are producing at rates that are better than anticipated. This was our third drilling program in the Champotran field since 2013, with a cumulative total of 13 wells, at a 100% success rate. After-tax rates of return associated with our Champotran oil drilling program remain in excess of 100%(2) at today's oil prices. The remainder of our 2015 capital activities in France will continue to focus on highly economic workovers and optimization projects, as well as infrastructure and facility maintenance. During the second quarter, we successfully restored approximately 2 mmcf/d (330 boe/d) of shut-in natural gas production from our Vic Bilh field.
In the Netherlands, we drilled two (1.9 net) wells during the quarter on the Slootdorp concession, in the province of North Holland. Both wells were successful, encountering more natural gas pay than expected. The first well, Slootdorp-06, encountered 70 meters of net natural gas pay in the Slochteren formation of the Rotliegend group. The second well, Slootdorp-07, encountered 41 meters of net natural gas pay in two separate intervals in the Zechstein Carbonate. Gross stabilized test flow rates(3) were 23.1 mmcf/d (3,850 boe/d) for Slootdorp-06 and 11.9 mmcf/d (2,000 boe/d) and 2.4 mmcf/d (400 boe/d), respectively, for the lower and upper Zechstein intervals of Slootdorp-07. Both wells are on sales during an extended production test to size additional production equipment. The wells are producing at a facility-restricted combined rate of 21 mmcf/d (3,500 boe/d) net. We completed planned major facility maintenance at the Garijp Treatment Centre in late June, which reduced production in the quarter by approximately 2,400 mcf/d (400 boe/d). The shutdown went as intended and the facility returned to service in late June.
In our non-operated German producing assets, our partner (ExxonMobil Production Deutschland GmbH) finished drilling and completing the Burgmoor Z3a well (25% net interest to Vermilion). The well was placed on production subsequent to the quarter and is currently producing at a rate of approximately 1.4 mmcf/d (230 boe/d), net to Vermilion.
At our non-operated Corrib project in Ireland, all natural gas terminal systems have now been commissioned. Following minor remaining compressor maintenance, operator Shell E&P Ireland Limited ("SEPIL") expects to declare all wells, facilities and transport systems (both offshore and onshore) ready for service by the end of August. SEPIL conducted a workover and production test of the Corrib P2 well during July, achieving a stabilized flow rate of 107 mmcf/d (17,830 boe/d)(4) gross. The P2 well is expected to be tied-in to the subsea production system during August, providing additional back-up to augment the deliverability of the other five wells in the Corrib field. With respect to remaining regulatory approvals, a Final Determination for the Corrib Industrial Emissions License ("IEL") from the Irish Environmental Protection Agency ("EPA") and a Ministerial Consent from Ireland's Department of Communications, Energy and Natural Resources must be received prior to commencing natural gas production. In accordance with statutory guidelines on applicable review periods, the EPA is expected to issue its Final Determination on the IEL on or before mid-September. We now estimate that the Ministerial Consent process will be completed, and that production will commence, in the early-to-mid fourth quarter of 2015. Production at Corrib is expected to increase over the first six months after first gas to peak production levels estimated at approximately 58 mmcf/d (approximately 9,700 boe/d), net to Vermilion.
While the final regulatory approvals are taking longer than we expected, we believe that we are very near the end of the regulatory process for Corrib. Our ability to maintain our 2015 production guidance (originally set in March 2014), despite foregoing approximately 3,000 net boe/d of planned calendar year average production from Corrib, is indicative of the operational and asset strength of our company. Moreover, we have maintained this production guidance while reducing 2015 capital expenditures by more than $200 million (over 30%) from 2014 levels. Upon commencement, Corrib production will further increase Vermilion's exposure to advantageously priced European natural gas.
With the compelling opportunities inherent in our overseas business units, and the significant operating flexibility offered by our Canadian asset base, planned activity levels for Canada in 2015 are less than in prior years. That being said, our Canadian opportunities continue to offer robust economics with the Cardium light-oil resource play generating capital investment rates of return of approximately 30%(2). Results to-date have been strong, with better-than-forecasted production volumes on our two-mile extended reach horizontal wells. In Q1 2015, we participated in the drilling of only seven (3.1 net) Cardium wells, which represented our planned Cardium drilling activities for 2015 (compared to 30 to 50 net wells in previous years). During Q2, we focused predominately on the completion and tie-in of previously drilled wells. Our Mannville condensate-rich conventional natural gas play remains the most economic play in our Canadian portfolio with current rates of return in excess of 100%(2). During Q1 2015, we participated in drilling 13 (8.9 net) wells followed by an additional one (0.5 net) well in Q2. In total, we plan on drilling approximately 30 (17.8 net) Mannville wells in 2015. During the second quarter, we also concluded a significant infrastructure project that included the expansion of a compressor station as well as the construction of a 22 km pipeline. This infrastructure will play a critical role in supporting the continued growth of the Mannville play. In Saskatchewan, we had previously reduced our drilling activity to five (4.1 net) wells for 2015, all of which were drilled in the first quarter. New well results in our downdip Midale play in southeast Saskatchewan have been better than we expected at the time we entered this area in 2014. Duvernay drilling activities have been deferred to beyond 2015 as we monitor the performance of our two appraisal wells drilled in 2014. In Alberta, we continue to be negatively impacted by plant capacity restrictions and interruptible service curtailments on the NGTL system, with approximately 1,700 boe/d of production offline during the second quarter.
In the United States, we drilled one gross (1 net) well in our Turner Sand resource play in the eastern Powder River Basin during the second quarter. We expect to complete this well during the third quarter of 2015.
To maintain financial flexibility in this commodity price environment, we further increased our existing revolving credit facilities from $1.75 billion to $2 billion during the second quarter. Taking into account this most recent expansion to our credit facility, we have approximately $775 million of borrowing capacity available. The facility, which matures in May 2019, is fully revolving up to the date of maturity and is subject to standard form covenants (discussed in the "Financial Position Review" section of our MD&A). We are, and we expect to continue to remain, in compliance with all applicable debt covenants, and expect to maintain our current dividend of $0.215 per share per month ($2.58 per share per year). We currently anticipate our balance sheet leverage to remain at current levels assuming consistent commodity prices, and then to naturally de-lever with the addition of FFO from our Corrib asset starting in the fourth quarter of 2015 and into 2016. While our current debt-to-cash flow ratio is higher than our targeted levels, it remains lower than the average debt ratio of our peer group. Our conservative financial management continues to provide us with the flexibility to manage our business effectively and provide continued growth and returns for shareholders in this challenging price environment.
During Q2, Vermilion was pleased to announce that for a sixth consecutive year, it has been recognized by the Great Place to Work® Institute as a Best Workplace in Canada and France. Vermilion was also recognized for a second consecutive year as a Best Workplace in the Netherlands in 2015, after becoming eligible for ranking in 2014. Vermilion is the only energy company in its category to rank on the Best Workplaces lists in Canada and the Netherlands, and the highest scoring energy company on the Best Workplaces list in France.
Vermilion was recently ranked 15th by Corporate Knights on the Future 40 Responsible Corporate Leaders in Canada list (the highest ranking for an oil and gas company, and improved from our debut ranking of 32nd last year). We were also named Top International Producer of the year by the Explorers and Producers Association of Canada. This recognition reflects Vermilion's continued focus on achieving robust shareholder returns combined with environmental, social and governance performance. Our non-financial initiatives and performance are also articulated in the Company's annual Carbon Disclosure Project (CDP) submissions and in our Sustainability Report (http://www.vermilionenergy.com/sustainability). Strong workplace practices and a culture that respects both people and communities are key elements in our success.
The management and directors of Vermilion continue to hold approximately 6% of the outstanding shares and remain committed to delivering superior rewards to all stakeholders. In spite of the challenges posed by the current business environment, we continue to believe that Vermilion is situated for long-term, diversified growth. We remain confident that the assets in our portfolio can support organic growth for future years, and in the current environment, we also find ourselves well positioned to take advantage of potential acquisition activity in both North American and international markets. Our long-term focus on the creation of real value through our technical capabilities, combined with our conservative financial approach and patience, should allow us to compete and transact for the benefit of our existing shareholders if suitable opportunities arise.
German Farm-In
Subsequent to the end of the second quarter, we entered into a definitive farm-in agreement (the "Farm-in" or the "Agreement") with Mobil Erdgas-Erdӧl GmbH ("MEEG") and BEB Erdgas und Erdӧl GmbH & Co.KG ("BEB"). MEEG is 100% held by ExxonMobil and BEB is jointly held by ExxonMobil and Royal Dutch Shell. ExxonMobil Production Deutschland GmbH ("EMPG") currently operates and manages both MEEG's and BEB's interests in the exploration licenses involved in the Farm-in. The Agreement, signed July 27, 2015 and with an anticipated closing date of January 1, 2016, remains subject to customary conditions and regulatory approvals.
The Farm-in will provide Vermilion participating interest in 19 onshore exploration licenses in northwest Germany, comprising approximately 850,000 net acres of oil and natural gas rights (100% undeveloped) (the "Assets"). Under the terms of the Agreement, Vermilion will acquire the Assets (which represent 50% of MEEG's and BEB's current interests in these licenses) in exchange for committing to the financial carry of the remaining 50% of MEEG's and BEB's interests in 11 gross (6 net) exploratory wells over the next five years. At present, approximately 75 exploratory and semi-exploratory leads and prospects have been identified in the Rotliegend, Carboniferous, Triassic and Zechstein formations on these lands. Eleven of the 19 licenses are currently operated by EMPG, which will transfer operatorship for the exploration phase to Vermilion. The Agreement also grants Vermilion proportional ownership to EMPG proprietary data spanning the Assets. No existing oil or natural gas production is being acquired by Vermilion in the Farm-in.
The Farm-in provides Vermilion with a large, nearly contiguous land block in the heart of the North German Basin. This basin has cumulative production of more than two billion barrels of oil and 34 trillion cubic feet of natural gas since its discovery, representing approximately 97% of Germany's historical onshore production. We believe that the Assets are prospective for both oil and natural gas. The Farm-in follows our entry in early 2014 into the exploration and production business in Germany, a jurisdiction with a long history of oil and natural gas development activity, a consistent fiscal framework and low political risk. The Assets are a natural and synergistic expansion to our existing German and Netherlands portfolios, and share the same subsurface genre and development approach. We believe that our capability in conventional oil and natural gas exploration and production in onshore Europe, coupled with our track record of accretive European consolidation, positions us for future development and expansion opportunities in both Germany and the greater European region.
Croatian Exploration Block Award
On June 3, 2015, we were conditionally awarded four exploration blocks in northeast Croatia near the Hungarian border, by the Croatian Hydrocarbon Agency. This award remains subject to successful execution of a definitive contract acceptable to both Vermilion and the Government of the Republic of Croatia. The four exploration blocks consist of approximately 2.35 million gross acres with a substantial portion of the acreage located near existing crude oil and natural gas fields. Capital commitments on the four blocks are modest and back-loaded. The initial 5-year exploration period consists of two phases with an option to relinquish the blocks following the initial 3-year phase. In aggregate, our capital commitments, excluding an initial bonus payment of €1.3 million, total approximately €7.3 million over the three-year mandatory phase, followed by an additional €11.6 million during the remaining two-year optional phase.
(1) | The above discussion includes additional GAAP and non-GAAP measures which may not be comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of Management's Discussion and Analysis. |
(2) | Economics calculated using the following commodity price deck assumptions: $50/bbl WTI; $55/bbl Dated Brent; $2.85/mmbtu AECO; CAD/USD 1.30; CAD/EUR 1.40. |
(3) | Slootdorp-06 (Slochteren) production test was performed over an 18-day test period at a maximum choke of 64/64" with approximately 45% drawdown over the test period. Slootdorp-07 (lower zone - Z2) production test was performed over a 4-hour test period at a maximum choke of 36/64" with approximately 35% drawdown over the test period. Slootdorp-07 (upper zone - Z3) production test was performed over a 12-hour test period at a maximum choke of 16/64" with approximately 40% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery. |
(4) | Corrib P2 well produces from the Sherwood sandstones. The production test was performed over a 12-hour period at a maximum choke of 80/64", achieving a peak production rate of 113 mmcf/d and a stabilized flow rate of 107 mmcf/d with approximately 30% drawdown over the test period. This test result is not necessarily indicative of long-term performance or of ultimate recovery. |
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is Management's Discussion and Analysis ("MD&A"), dated August 6, 2015, of Vermilion Energy Inc.'s ("Vermilion", "We", "Our", "Us" or the "Company") operating and financial results as at and for the three and six months ended June 30, 2015 compared with the corresponding periods in the prior year.
This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2015 and the audited consolidated financial statements for the year ended December 31, 2014 and 2013, together with accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
The unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2015 and comparative information have been prepared in Canadian dollars, except where another currency is indicated, and in accordance with IAS 34, "Interim Financial Reporting", as issued by the International Accounting Standard Board ("IASB").
This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by International Financial Reporting Standards ("IFRS"). As such, these financial measures are considered additional GAAP or non-GAAP financial measures and therefore are unlikely to be comparable with similar financial measures presented by other issuers. These additional GAAP and non-GAAP financial measures include:
For a full description of these and other non-GAAP financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES".
VERMILION'S BUSINESS
Vermilion is a Calgary, Alberta based international oil and gas producer focused on the acquisition, development and optimization of producing properties in North America, Europe, and Australia. We manage our business through our Calgary head office and our international business unit offices.
This MD&A separately discusses each of our business units in addition to our corporate segment.
GUIDANCE
We first issued 2015 capital expenditure guidance of $525 million on December 8, 2014. We subsequently adjusted our 2015 capital expenditure guidance to $415 million on February 27, 2015, in response to the continued weakness in commodity prices. That reduction reflected lower planned activity levels, including the deferral of our Australian drilling campaign. On August 10, 2015 we announced an increase in our capital expenditure guidance of $70 million to $485 million following the reinstatement of the Australian drilling campaign as well as additional funding for projects in Canada, France and Ireland. We are maintaining our previous production guidance of 55,000-57,000 boe/d, albeit towards the lower end of our guidance range due to later-than-originally expected first gas from Corrib.
The following table summarizes our 2015 guidance:
Date | Capital Expenditures ($MM) | Production (boe/d) | ||||||||||||||
2015 - Guidance | ||||||||||||||||
2015 Guidance | December 8, 2014 | 525 | 55,000 to 57,000 | |||||||||||||
2015 Guidance | February 27, 2015 | 415 | 55,000 to 57,000 | |||||||||||||
2015 Guidance | August 10, 2015 | 485 | 55,000 to 57,000 |
SHAREHOLDER RETURN
Vermilion strives to provide investors with reliable and growing dividends in addition to sustainable, global production growth. The following table, as of June 30, 2015, reflects our trailing one, three, and five year performance:
Total return (1) | Trailing One Year | Trailing Three Year | Trailing Five Year | |||||||||
Dividends per Vermilion share | $2.58 | $7.41 | $11.97 | |||||||||
Capital appreciation per Vermilion share | -$20.30 | $7.98 | $20.28 | |||||||||
Total return per Vermilion share | -23.9% | 33.5% | 95.8% | |||||||||
Annualized total return per Vermilion share | -23.9% | 10.1% | 14.4% | |||||||||
Annualized total return on the S&P TSX High Income Energy Index | -32.2% | -2.9% | 0.4% |
(1) |
The above table includes non-GAAP financial measures which may not be
comparable to other companies. Please see the "ADDITIONAL AND NON-GAAP FINANCIAL MEASURES" section of this MD&A. |
CONSOLIDATED RESULTS OVERVIEW
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||||||||||
Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | ||||||||||||||||||
2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | ||||||||||||||||||
Production | |||||||||||||||||||||||||
Crude oil (bbls/d) | 28,916 | 28,181 | 30,184 | 3% | (4%) | 28,550 | 28,759 | (1%) | |||||||||||||||||
NGLs (bbls/d) | 3,867 | 3,039 | 2,892 | 27% | 34% | 3,455 | 2,518 | 37% | |||||||||||||||||
Natural gas (mmcf/d) | 114.29 | 115.00 | 114.08 | (1%) | - | 114.64 | 108.73 | 5% | |||||||||||||||||
Total (boe/d) | 51,831 | 50,386 | 52,089 | 3% | - | 51,113 | 49,398 | 3% | |||||||||||||||||
Build (draw) in inventory (mbbl) | (121) | 383 | 67 | 262 | (31) | ||||||||||||||||||||
Financial metrics | |||||||||||||||||||||||||
Fund flows from operations ($M) | 129,496 | 120,795 | 216,076 | 7% | (40%) | 250,291 | 421,439 | (41%) | |||||||||||||||||
Per share ($/basic share) | 1.18 | 1.12 | 2.05 | 5% | (42%) | 2.31 | 4.05 | (43%) | |||||||||||||||||
Net earnings ($M) | 6,813 | 1,275 | 53,993 | 434% | (87%) | 8,088 | 156,781 | (95%) | |||||||||||||||||
Per share ($/basic share) | 0.06 | 0.01 | 0.51 | 500% | (88%) | 0.07 | 1.51 | (95%) | |||||||||||||||||
Cash flows from operating activities ($M) | 134,668 | 22,647 | 149,592 | 495% | (10%) | 157,315 | 327,830 | (52%) | |||||||||||||||||
Net debt ($M) | 1,377,902 | 1,388,603 | 1,168,998 | (1%) | 18% | 1,377,902 | 1,168,998 | 18% | |||||||||||||||||
Cash dividends ($/share) | 0.645 | 0.645 | 0.645 | - | - | 1.290 | 1.290 | - | |||||||||||||||||
Activity | |||||||||||||||||||||||||
Capital expenditures ($M) | 90,173 | 174,311 | 135,073 | (48%) | (33%) | 264,484 | 331,448 | (20%) | |||||||||||||||||
Acquisitions ($M) | 480 | 35 | 381,139 | 1,271% | (100%) | 515 | 559,366 | (100%) | |||||||||||||||||
Gross wells drilled | 5.00 | 29.00 | 13.00 | 34.00 | 37.00 | ||||||||||||||||||||
Net wells drilled | 3.61 | 20.04 | 6.72 | 23.65 | 25.55 |
Operational review
Financial review
Net earnings
Cash flows from operating activities
Fund flows from operations
Net debt
Dividends
COMMODITY PRICES
Three Months Ended | % change | Six Months Ended | % change | |||||||||||||||||||||
Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||
2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||||||||||
Average reference prices | ||||||||||||||||||||||||
WTI (US $/bbl) | 57.94 | 48.63 | 102.99 | 19% | (44%) | 53.29 | 100.84 | (47%) | ||||||||||||||||
Edmonton Sweet index (US $/bbl) | 55.08 | 41.83 | 96.85 | 32% | (43%) | 48.46 | 93.65 | (48%) | ||||||||||||||||
Dated Brent (US $/bbl) | 61.92 | 53.97 | 109.63 | 15% | (44%) | 57.95 | 108.93 | (47%) | ||||||||||||||||
AECO ($/GJ) | 2.52 | 2.60 | 4.44 | (3%) | (43%) | 2.56 | 4.93 | (48%) | ||||||||||||||||
TTF ($/GJ) | 7.94 | 8.25 | 7.91 | (4%) | - | 8.10 | 9.02 | (10%) | ||||||||||||||||
TTF (€/GJ) | 5.84 | 5.91 | 5.27 | (1%) | 11% | 5.87 | 6.01 | (2%) | ||||||||||||||||
Average foreign currency exchange rates | ||||||||||||||||||||||||
CDN $/US $ | 1.23 | 1.24 | 1.09 | (1%) | 13% | 1.24 | 1.10 | 13% | ||||||||||||||||
CDN $/Euro | 1.36 | 1.40 | 1.50 | (3%) | (9%) | 1.38 | 1.50 | (8%) | ||||||||||||||||
Average realized prices ($/boe) | ||||||||||||||||||||||||
Canada | 40.59 | 35.81 | 71.56 | 13% | (43%) | 38.24 | 70.55 | (46%) | ||||||||||||||||
France | 71.96 | 64.33 | 117.29 | 12% | (39%) | 68.52 | 117.41 | (42%) | ||||||||||||||||
Netherlands | 47.63 | 48.60 | 48.14 | (2%) | (1%) | 48.13 | 56.06 | (14%) | ||||||||||||||||
Germany | 43.31 | 45.21 | 45.36 | (4%) | (5%) | 44.27 | 49.50 | (11%) | ||||||||||||||||
Australia | 80.87 | 83.80 | 126.87 | (3%) | (36%) | 81.60 | 127.11 | (36%) | ||||||||||||||||
United States | 60.57 | 48.79 | - | 24% | 100% | 54.07 | - | 100% | ||||||||||||||||
Consolidated | 54.65 | 47.17 | 82.96 | 16% | (34%) | 51.19 | 85.70 | (40%) | ||||||||||||||||
Production mix (% of production) | ||||||||||||||||||||||||
% priced with reference to WTI | 27% | 28% | 30% | 27% | 27% | |||||||||||||||||||
% priced with reference to AECO | 21% | 20% | 18% | 21% | 18% | |||||||||||||||||||
% priced with reference to TTF | 16% | 18% | 18% | 17% | 19% | |||||||||||||||||||
% priced with reference to Dated Brent | 36% | 34% | 34% | 35% | 36% |
Reference prices
Realized prices
FUND FLOWS FROM OPERATIONS
Three Months Ended | Six Months Ended | |||||||||||||||||||||||||||||
Jun 30, 2015 | Mar 31, 2015 | Jun 30, 2014 | Jun 30, 2015 | Jun 30, 2014 | ||||||||||||||||||||||||||
$M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | |||||||||||||||||||||
Petroleum and natural gas sales | 264,331 | 54.65 | 195,885 | 47.17 | 387,684 | 82.96 | 460,216 | 51.19 | 768,867 | 85.70 | ||||||||||||||||||||
Royalties | (16,111) | (3.33) | (16,424) | (3.95) | (29,013) | (6.21) | (32,535) | (3.62) | (53,037) | (5.91) | ||||||||||||||||||||
Petroleum and natural gas revenues | 248,220 | 51.32 | 179,461 | 43.22 | 358,671 | 76.75 | 427,681 | 47.57 | 715,830 | 79.79 | ||||||||||||||||||||
Transportation expense | (10,883) | (2.25) | (9,540) | (2.30) | (12,032) | (2.57) | (20,423) | (2.27) | (21,893) | (2.44) | ||||||||||||||||||||
Operating expense | (58,616) | (12.12) | (43,851) | (10.56) | (58,213) | (12.46) | (102,467) | (11.40) | (116,199) | (12.95) | ||||||||||||||||||||
General and administration | (14,505) | (3.00) | (13,560) | (3.27) | (17,762) | (3.80) | (28,065) | (3.12) | (32,229) | (3.59) | ||||||||||||||||||||
PRRT | (3,371) | (0.70) | (2,354) | (0.57) | (12,699) | (2.72) | (5,725) | (0.64) | (32,938) | (3.67) | ||||||||||||||||||||
Corporate income taxes | (17,344) | (3.59) | (17,623) | (4.24) | (32,635) | (6.98) | (34,967) | (3.89) | (71,238) | (7.94) | ||||||||||||||||||||
Interest expense | (14,550) | (3.01) | (13,298) | (3.20) | (12,334) | (2.64) | (27,848) | (3.10) | (23,794) | (2.65) | ||||||||||||||||||||
Realized gain on derivative instruments | 3,081 | 0.64 | 6,257 | 1.51 | 2,419 | 0.52 | 9,338 | 1.04 | 5,059 | 0.56 | ||||||||||||||||||||
Realized foreign exchange (loss) gain | (2,740) | (0.57) | 3,306 | 0.78 | 587 | 0.12 | 566 | 0.06 | (1,454) | (0.16) | ||||||||||||||||||||
Realized other income | 204 | 0.04 | 31,997 | 7.70 | 74 | 0.02 | 32,201 | 3.58 | 295 | 0.03 | ||||||||||||||||||||
Fund flows from operations | 129,496 | 26.76 | 120,795 | 29.07 | 216,076 | 46.24 | 250,291 | 27.83 | 421,439 | 46.98 |
The following table shows a reconciliation of the change in fund flows from operations:
($M) | Q2/15 vs. Q1/15 | Q2/15 vs. Q2/14 | 2015 vs. 2014 | |||||||||||
Fund flows from operations - Comparative period | 120,795 | 216,076 | 421,439 | |||||||||||
Sales volume variance: | ||||||||||||||
Canada | 1,950 | (10,845) | 15,826 | |||||||||||
France | 12,285 | 6,751 | (1,469) | |||||||||||
Netherlands | (2,407) | (5,585) | (12,187) | |||||||||||
Germany | (313) | 30 | 4,606 | |||||||||||
Australia | 38,956 | 29,345 | (31,213) | |||||||||||
United States | (127) | 677 | 1,349 | |||||||||||
Pricing variance on sold volumes: | ||||||||||||||
WTI | 12,700 | (50,424) | (108,609) | |||||||||||
AECO | (1,118) | (10,708) | (24,490) | |||||||||||
Dated Brent | 7,474 | (81,710) | (141,350) | |||||||||||
TTF | (954) | (884) | (11,114) | |||||||||||
Changes in: | ||||||||||||||
Royalties | 313 | 12,902 | 20,502 | |||||||||||
Transportation | (1,343) | 1,149 | 1,470 | |||||||||||
Operating expense | (14,765) | (403) | 13,732 | |||||||||||
General and administration | (945) | 3,257 | 4,164 | |||||||||||
PRRT | (1,017) | 9,328 | 27,213 | |||||||||||
Corporate income taxes | 279 | 15,291 | 36,271 | |||||||||||
Interest | (1,252) | (2,216) | (4,054) | |||||||||||
Realized derivatives | (3,176) | 662 | 4,279 | |||||||||||
Realized foreign exchange | (6,046) | (3,327) | 2,020 | |||||||||||
Realized other income | (31,793) | 130 | 31,906 | |||||||||||
Fund flows from operations - Current period | 129,496 | 129,496 | 250,291 |
Fund flows from operations of $129.5 million during Q2 2015 represented an increase of 7% versus Q1 2015. This quarter-over-quarter increase was principally the result of higher sales volumes and stronger crude oil pricing. Sales increased by $68.4 million, which included a $50.3 million sales volumes variance driven by increased sales in Australia ($39.0 million) and France ($12.3 million). Both Australia and France were impacted by inventory variances, where Australia had an inventory draw of 162,000 bbls (as compared to a build of 281,000 bbls) and France's inventory increased by 41,000 bbls (as compared to a build of 102,000 bbls). The increase in fund flows from operations was further impacted by an $18.1 million favorable pricing variance driven by higher crude oil prices. Higher sold volumes and crude oil pricing was partially offset by higher operating expenses resulting from the recognition of inventoried operating costs in Australia, as well as the absence of the previously mentioned recovery of costs in France.
Fund flows from operations decreased by 40% and 41% for the three and six months ended June 30, 2015, respectively, versus the comparable periods in the prior year. This decrease was primarily driven by unfavorable crude oil and natural gas pricing variances, partially offset by favorable royalty and tax variances. For the three months ended June 30, 2015, the decrease in fund flows from operations was further offset by a favorable sales variance of $20.4 million driven by increased sold volume in Australia. For the six months ended June 30, 2015, the decrease in fund flows from operations was further impacted by a $23.1 million unfavorable sales variance, driven by a build in inventory of 262,000 bbls (as compared to a draw of 31,000 bbls in the comparative period), partially offset by the previously mentioned recovery of costs in France.
Fluctuations in fund flows from operations (and correspondingly net earnings and cash flows from operating activities) may occur as a result of changes in commodity prices and costs to produce petroleum and natural gas. In addition, fund flows from operations may be highly affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized in fund flows from operations.
CANADA BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Six Months Ended | % change | |||||||||||||||||||||||
Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||||
Canada business unit | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | ||||||||||||||||||
Production | ||||||||||||||||||||||||||
Crude oil (bbls/d) | 10,182 | 10,893 | 12,676 | (7%) | (20%) | 10,535 | 11,065 | (5%) | ||||||||||||||||||
NGLs (bbls/d) | 3,755 | 2,976 | 2,796 | 26% | 34% | 3,367 | 2,435 | 38% | ||||||||||||||||||
Natural gas (mmcf/d) | 64.66 | 61.78 | 57.59 | 5% | 12% | 63.23 | 53.58 | 18% | ||||||||||||||||||
Total (boe/d) | 24,713 | 24,165 | 25,070 | 2% | (1%) | 24,441 | 22,430 | 9% | ||||||||||||||||||
Production mix (% of total) | ||||||||||||||||||||||||||
Crude oil | 41% | 45% | 51% | 43% | 49% | |||||||||||||||||||||
NGLs | 15% | 12% | 11% | 14% | 11% | |||||||||||||||||||||
Natural gas | 44% | 43% | 38% | 43% | 40% | |||||||||||||||||||||
Activity | ||||||||||||||||||||||||||
Capital expenditures ($M) | 21,881 | 114,849 | 36,968 | (81%) | (41%) | 136,730 | 151,907 | (10%) | ||||||||||||||||||
Acquisitions ($M) | 384 | 35 | 381,326 | 419 | 386,094 | |||||||||||||||||||||
Gross wells drilled | 1.00 | 25.00 | 9.00 | 26.00 | 29.00 | |||||||||||||||||||||
Net wells drilled | 0.50 | 16.04 | 3.29 | 16.54 | 18.26 |
Production
Activity review
Cardium
Mannville
Saskatchewan
Financial review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||||||||||
Canada business unit | Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||
($M except as indicated) | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||||||||||
Sales | 91,284 | 77,884 | 163,261 | 17% | (44%) | 169,168 | 286,441 | (41%) | |||||||||||||||||
Royalties | (5,768) | (8,592) | (18,240) | (33%) | (68%) | (14,360) | (30,903) | (54%) | |||||||||||||||||
Transportation expense | (4,469) | (3,942) | (4,024) | 13% | 11% | (8,411) | (7,122) | 18% | |||||||||||||||||
Operating expense | (21,534) | (19,099) | (21,179) | 13% | 2% | (40,633) | (37,789) | 8% | |||||||||||||||||
General and administration | (5,510) | (4,015) | (6,560) | 37% | (16%) | (9,525) | (9,428) | 1% | |||||||||||||||||
Fund flows from operations | 54,003 | 42,236 | 113,258 | 28% | (52%) | 96,239 | 201,199 | (52%) | |||||||||||||||||
Netbacks ($/boe) | |||||||||||||||||||||||||
Sales | 40.59 | 35.81 | 71.56 | 13% | (43%) | 38.24 | 70.55 | (46%) | |||||||||||||||||
Royalties | (2.56) | (3.95) | (7.99) | (35%) | (68%) | (3.25) | (7.61) | (57%) | |||||||||||||||||
Transportation expense | (1.99) | (1.81) | (1.76) | 10% | 13% | (1.90) | (1.75) | 9% | |||||||||||||||||
Operating expense | (9.58) | (8.78) | (9.28) | 9% | 3% | (9.19) | (9.31) | (1%) | |||||||||||||||||
General and administration | (2.45) | (1.85) | (2.88) | 32% | (15%) | (2.15) | (2.32) | (7%) | |||||||||||||||||
Fund flows from operations netback | 24.01 | 19.42 | 49.65 | 24% | (52%) | 21.75 | 49.56 | (56%) | |||||||||||||||||
Reference prices | |||||||||||||||||||||||||
WTI (US $/bbl) | 57.94 | 48.63 | 102.99 | 19% | (44%) | 53.29 | 100.84 | (47%) | |||||||||||||||||
Edmonton Sweet index (US $/bbl) | 55.08 | 41.83 | 96.85 | 32% | (43%) | 48.46 | 93.65 | (48%) | |||||||||||||||||
Edmonton Sweet index ($/bbl) | 67.72 | 51.92 | 105.61 | 30% | (36%) | 59.86 | 102.73 | (42%) | |||||||||||||||||
AECO ($/GJ) | 2.52 | 2.60 | 4.44 | (3%) | (43%) | 2.56 | 4.93 | (48%) |
Sales
Royalties
Transportation
Operating expense
General and administration
FRANCE BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Six Months Ended | % change | |||||||||||||||||||||||
Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||||
France business unit | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | ||||||||||||||||||
Production | ||||||||||||||||||||||||||
Crude oil (bbls/d) | 12,746 | 11,463 | 11,025 | 11% | 16% | 12,108 | 10,899 | 11% | ||||||||||||||||||
Natural gas (mmcf/d) | 1.03 | - | - | 100% | 100% | 0.52 | - | 100% | ||||||||||||||||||
Total (boe/d) | 12,917 | 11,463 | 11,025 | 13% | 17% | 12,194 | 10,899 | 12% | ||||||||||||||||||
Inventory (mbbls) | ||||||||||||||||||||||||||
Opening crude oil inventory | 299 | 197 | 238 | 197 | 269 | |||||||||||||||||||||
Crude oil production | 1,160 | 1,032 | 1,003 | 2,192 | 1,973 | |||||||||||||||||||||
Crude oil sales | (1,119) | (930) | (1,062) | (2,049) | (2,063) | |||||||||||||||||||||
Closing crude oil inventory | 340 | 299 | 179 | 340 | 179 | |||||||||||||||||||||
Production mix (% of total) | ||||||||||||||||||||||||||
Crude oil | 99% | 100% | 100% | 99% | 100% | |||||||||||||||||||||
Natural gas | 1% | - | - | 1% | - | |||||||||||||||||||||
Activity | ||||||||||||||||||||||||||
Capital expenditures ($M) | 16,697 | 34,114 | 37,614 | (51%) | (56%) | 50,811 | 75,581 | (33%) | ||||||||||||||||||
Acquisitions ($M) | 96 | - | - | 96 | - | |||||||||||||||||||||
Gross wells drilled | - | 4.00 | 2.00 | 4.00 | 4.00 | |||||||||||||||||||||
Net wells drilled | - | 4.00 | 2.00 | 4.00 | 4.00 |
Production
Activity review
Financial review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||||||||||
France business unit | Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||
($M except as indicated) | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||||||||||
Sales | 81,627 | 59,832 | 124,617 | 36% | (34%) | 141,459 | 242,177 | (42%) | |||||||||||||||||
Royalties | (6,620) | (5,102) | (7,796) | 30% | (15%) | (11,722) | (15,147) | (23%) | |||||||||||||||||
Transportation expense | (3,526) | (3,011) | (5,385) | 17% | (35%) | (6,537) | (10,138) | (36%) | |||||||||||||||||
Operating expense | (12,102) | (10,826) | (16,550) | 12% | (27%) | (22,928) | (32,970) | (30%) | |||||||||||||||||
General and administration | (4,874) | (5,111) | (5,559) | (5%) | (12%) | (9,985) | (10,753) | (7%) | |||||||||||||||||
Other income | - | 31,775 | - | (100%) | - | 31,775 | - | 100% | |||||||||||||||||
Current income taxes | (9,316) | (14,281) | (24,761) | (35%) | (62%) | (23,597) | (50,025) | (53%) | |||||||||||||||||
Fund flows from operations | 45,189 | 53,276 | 64,566 | (15%) | (30%) | 98,465 | 123,144 | (20%) | |||||||||||||||||
Netbacks ($/boe) | |||||||||||||||||||||||||
Sales | 71.96 | 64.33 | 117.29 | 12% | (39%) | 68.52 | 117.41 | (42%) | |||||||||||||||||
Royalties | (5.84) | (5.49) | (7.34) | 6% | (20%) | (5.68) | (7.34) | (23%) | |||||||||||||||||
Transportation expense | (3.11) | (3.24) | (5.07) | (4%) | (39%) | (3.17) | (4.91) | (35%) | |||||||||||||||||
Operating expense | (10.67) | (11.64) | (15.58) | (8%) | (32%) | (11.11) | (15.98) | (30%) | |||||||||||||||||
General and administration | (4.30) | (5.49) | (5.24) | (22%) | (18%) | (4.84) | (5.21) | (7%) | |||||||||||||||||
Other income | - | 34.16 | - | (100%) | - | 15.39 | - | 100% | |||||||||||||||||
Current income taxes | (8.21) | (15.35) | (23.30) | (47%) | (65%) | (11.43) | (24.25) | (53%) | |||||||||||||||||
Fund flows from operations netback | 39.83 | 57.28 | 60.76 | (30%) | (34%) | 47.68 | 59.72 | (20%) | |||||||||||||||||
Reference prices | |||||||||||||||||||||||||
Dated Brent (US $/bbl) | 61.92 | 53.97 | 109.63 | 15% | (44%) | 57.95 | 108.93 | (47%) | |||||||||||||||||
Dated Brent ($/bbl) | 76.12 | 66.98 | 119.55 | 14% | (36%) | 71.59 | 119.50 | (40%) |
Sales
Royalties
Transportation
Operating expense
General and administration
Other income
Current income taxes
NETHERLANDS BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Six Months Ended | % change | |||||||||||||||||||||||
Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||||
Netherlands business unit | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | ||||||||||||||||||
Production | ||||||||||||||||||||||||||
NGLs (bbls/d) | 112 | 63 | 96 | 78% | 17% | 88 | 83 | 6% | ||||||||||||||||||
Natural gas (mmcf/d) | 32.43 | 36.41 | 40.35 | (11%) | (20%) | 34.41 | 41.74 | (18%) | ||||||||||||||||||
Total (boe/d) | 5,517 | 6,132 | 6,822 | (10%) | (19%) | 5,823 | 7,040 | (17%) | ||||||||||||||||||
Activity | ||||||||||||||||||||||||||
Capital expenditures ($M) | 18,885 | 4,333 | 21,513 | 336% | (12%) | 23,218 | 41,631 | (44%) | ||||||||||||||||||
Gross wells drilled | 2.00 | - | 2.00 | 2.00 | 4.00 | |||||||||||||||||||||
Net wells drilled | 1.86 | - | 1.43 | 1.86 | 3.29 |
Production
Activity review
Financial review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||||||||||
Netherlands business unit | Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||
($M except as indicated) | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||||||||||
Sales | 23,913 | 26,818 | 29,881 | (11%) | (20%) | 50,731 | 71,435 | (29%) | |||||||||||||||||
Royalties | (1,294) | (926) | (693) | 40% | 87% | (2,220) | (2,901) | (23%) | |||||||||||||||||
Operating expense | (5,414) | (5,826) | (6,390) | (7%) | (15%) | (11,240) | (12,432) | (10%) | |||||||||||||||||
General and administration | (454) | (737) | (326) | (38%) | 39% | (1,191) | (924) | 29% | |||||||||||||||||
Current income taxes | (2,347) | (2,388) | (1,301) | (2%) | 80% | (4,735) | (5,089) | (7%) | |||||||||||||||||
Fund flows from operations | 14,404 | 16,941 | 21,171 | (15%) | (32%) | 31,345 | 50,089 | (37%) | |||||||||||||||||
Netbacks ($/boe) | |||||||||||||||||||||||||
Sales | 47.63 | 48.60 | 48.14 | (2%) | (1%) | 48.13 | 56.06 | (14%) | |||||||||||||||||
Royalties | (2.58) | (1.68) | (1.12) | 54% | 130% | (2.11) | (2.28) | (7%) | |||||||||||||||||
Operating expense | (10.78) | (10.56) | (10.29) | 2% | 5% | (10.66) | (9.76) | 9% | |||||||||||||||||
General and administration | (0.90) | (1.34) | (0.53) | (33%) | 70% | (1.13) | (0.73) | 55% | |||||||||||||||||
Current income taxes | (4.67) | (4.33) | (2.10) | 8% | 122% | (4.49) | (3.99) | 13% | |||||||||||||||||
Fund flows from operations netback | 28.70 | 30.69 | 34.10 | (6%) | (16%) | 29.74 | 39.30 | (24%) | |||||||||||||||||
Reference prices | |||||||||||||||||||||||||
TTF ($/GJ) | 7.94 | 8.25 | 7.91 | (4%) | - | 8.10 | 9.02 | (10%) | |||||||||||||||||
TTF (€/GJ) | 5.84 | 5.91 | 5.27 | (1%) | 11% | 5.87 | 6.01 | (2%) |
Sales
Royalties
Transportation expense
Operating expense
General and administration
Current income taxes
GERMANY BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||||||||||||
Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | ||||||||||||||||||||
Germany business unit | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||||||||||||
Production | |||||||||||||||||||||||||||
Natural gas (mmcf/d) | 16.18 | 16.80 | 16.13 | (4%) | - | 16.49 | 13.40 | 23% | |||||||||||||||||||
Total (boe/d) | 2,696 | 2,801 | 2,689 | (4%) | - | 2,748 | 2,234 | 23% | |||||||||||||||||||
Activity | |||||||||||||||||||||||||||
Capital expenditures ($M) | 3,231 | 968 | 630 | 234% | 413% | 4,199 | 826 | 408% | |||||||||||||||||||
Acquisitions ($M) | - | - | - | - | 172,871 | ||||||||||||||||||||||
Gross wells drilled | 1.00 | - | - | 1.00 | - | ||||||||||||||||||||||
Net wells drilled | 0.25 | - | - | 0.25 | - |
Production
Activity review
Financial review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||||||||||
Germany business unit | Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||
($M except as indicated) | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||||||||||
Sales | 10,626 | 11,395 | 11,097 | (7%) | (4%) | 22,021 | 20,012 | 10% | |||||||||||||||||
Royalties | (2,238) | (1,598) | (2,284) | 40% | (2%) | (3,836) | (4,086) | (6%) | |||||||||||||||||
Transportation expense | (1,240) | (894) | (1,052) | 39% | 18% | (2,134) | (1,474) | 45% | |||||||||||||||||
Operating expense | (1,373) | (1,999) | (2,043) | (31%) | (33%) | (3,372) | (3,597) | (6%) | |||||||||||||||||
General and administration | (1,435) | (1,608) | (830) | (11%) | 73% | (3,043) | (1,398) | 118% | |||||||||||||||||
Current income taxes | - | - | (506) | - | (100%) | - | (1,043) | (100%) | |||||||||||||||||
Fund flows from operations | 4,340 | 5,296 | 4,382 | (18%) | (1%) | 9,636 | 8,414 | 15% | |||||||||||||||||
Netbacks ($/boe) | |||||||||||||||||||||||||
Sales | 43.31 | 45.21 | 45.36 | (4%) | (5%) | 44.27 | 49.50 | (11%) | |||||||||||||||||
Royalties | (9.12) | (6.34) | (9.34) | 44% | (2%) | (7.71) | (10.11) | (24%) | |||||||||||||||||
Transportation expense | (5.05) | (3.55) | (4.30) | 42% | 17% | (4.29) | (3.65) | 18% | |||||||||||||||||
Operating expense | (5.60) | (7.93) | (8.35) | (29%) | (33%) | (6.78) | (8.90) | (24%) | |||||||||||||||||
General and administration | (5.85) | (6.38) | (3.39) | (8%) | 73% | (6.12) | (3.46) | 77% | |||||||||||||||||
Current income taxes | - | - | (2.07) | - | (100%) | - | (2.58) | (100%) | |||||||||||||||||
Fund flows from operations netback | 17.69 | 21.01 | 17.91 | (16%) | (1%) | 19.37 | 20.80 | (7%) | |||||||||||||||||
Reference prices | |||||||||||||||||||||||||
TTF ($/GJ) | 7.94 | 8.25 | 7.91 | (4%) | - | 8.10 | 9.02 | (10%) | |||||||||||||||||
TTF (€/GJ) | 5.84 | 5.91 | 5.27 | (1%) | 11% | 5.87 | 6.01 | (2%) |
Sales
Royalties
Transportation expense
Operating expense
General and administration
Current income taxes
IRELAND BUSINESS UNIT
Overview
Operational and financial review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||||||||||||
Ireland business unit | Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||||||||||||||||
($M) | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||||||||||||
Transportation expense | (1,648) | (1,693) | (1,571) | (3%) | 5% | (3,341) | (3,159) | 6% | |||||||||||||||||||
General and administration | (628) | (512) | (252) | 23% | 149% | (1,140) | (534) | 113% | |||||||||||||||||||
Fund flows from operations | (2,276) | (2,205) | (1,823) | 3% | 25% | (4,481) | (3,693) | 21% | |||||||||||||||||||
Activity | |||||||||||||||||||||||||||
Capital expenditures | 20,267 | 12,955 | 27,221 | 56% | (26%) | 33,222 | 43,457 | (24%) |
Activity review
Transportation expense
AUSTRALIA BUSINESS UNIT
Overview
Operational review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||||||
Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | ||||||||||
Australia business unit | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||||||
Production | |||||||||||||||||
Crude oil (bbls/d) | 5,865 | 5,672 | 6,483 | 3% | (10%) | 5,769 | 6,795 | (15%) | |||||||||
Inventory (mbbls) | |||||||||||||||||
Opening crude oil inventory | 318 | 37 | 63 | 37 | 130 | ||||||||||||
Crude oil production | 534 | 511 | 590 | 1,044 | 1,230 | ||||||||||||
Crude oil sales | (696) | (230) | (464) | (925) | (1,171) | ||||||||||||
Closing crude oil inventory | 156 | 318 | 189 | 156 | 189 | ||||||||||||
Activity | |||||||||||||||||
Capital expenditures ($M) | 6,468 | 6,455 | 10,991 | - | (41%) | 12,923 | 16,682 | (23%) | |||||||||
Production
Activity review
Financial review
Three Months Ended | % change | Six Months Ended | % change | ||||||||||
Australia business unit | Jun 30, | Mar 31, | Jun 30, | Q2/15 vs. | Q2/15 vs. | Jun 30, | Jun 30, | 2015 vs. | |||||
($M except as indicated) | 2015 | 2015 | 2014 | Q1/15 | Q2/14 | 2015 | 2014 | 2014 | |||||
Sales | 56,204 | 19,284 | 58,828 | 191% | (4%) | 75,488 | 148,802 | (49%) | |||||
Operating expense | (18,083) | (5,886) | (12,051) | 207% | 50% | (23,969) | (29,411) | (19%) | |||||
General and administration | (1,141) | (1,454) | (1,661) | (22%) | (31%) | (2,595) | (2,867) | (9%) | |||||
PRRT | (3,371) | (2,354) | (12,699) | 43% | (73%) | (5,725) | (32,938) | (83%) | |||||
Corporate income taxes | (5,134) | (577) | (5,689) | 790% | (10%) | (5,711) | (14,530) | (61%) | |||||
Fund flows from operations | 28,475 | 9,013 | 26,728 | 216% | 7% | 37,488 | 69,056 | (46%) | |||||
Netbacks ($/boe) | |||||||||||||
Sales | 80.87 | 83.80 | 126.87 | (3%) | (36%) | 81.60 | 127.11 | (36%) | |||||
Operating expense | (26.02) | (25.58) | (25.99) | 2% | - | (25.91) | (25.12) | 3% | |||||
General and administration | (1.64) | (6.32) | (3.58) | (74%) | (54%) | (2.81) | (2.45) | 15% | |||||
PRRT | (4.85) | (10.23) | (27.39) | (53%) | (82%) | (6.19) | (28.14) | (78%) | |||||
Corporate income taxes | (7.39) | (2.51) | (12.27) | 194% | (40%) | (6.17) | (12.41) | (50%) | |||||
Fund flows from operations netback | 40.97 | 39.16 | 57.64 | 5% | (29%) | 40.52 | 58.99 | (31%) | |||||
Reference prices | |||||||||||||
Dated Brent (US $/bbl) | 61.92 | 53.97 | 109.63 | 15% | (44%) | 57.95 | 108.93 | (47%) | |||||
Dated Brent ($/bbl) | 76.12 | 66.98 | 119.55 | 14% | (36%) | 71.59 | 119.50 | (40%) | |||||
Sales
Royalties and transportation expense
Operating expense
General and administration
PRRT and corporate income taxes
UNITED STATES BUSINESS UNIT
Overview
Operational and financial review
Three Months Ended | % change | ||||||
United States business unit | Jun 30, | Mar 31, | Q2/15 vs. | ||||
($M except as indicated) | 2015 | 2015 | Q1/15 | ||||
Sales | 677 | 672 | 1% | ||||
Royalties | (191) | (206) | (7%) | ||||
Operating expense | (110) | (215) | (49%) | ||||
General and administration | (963) | (1,080) | (11%) | ||||
Fund flows from operations | (587) | (829) | (29%) | ||||
Netbacks ($/boe) | |||||||
Sales | 60.57 | 48.79 | 24% | ||||
Royalties | (17.08) | (14.98) | 14% | ||||
Operating expense | (9.88) | (15.61) | (37%) | ||||
General and administration | (86.12) | (78.41) | 10% | ||||
Fund flows from operations netback | (52.51) | (60.21) | (13%) | ||||
Reference prices | |||||||
WTI (US $/bbl) | 57.94 | 48.63 | 19% | ||||
WTI ($/bbl) | 71.23 | 60.35 | 18% | ||||
Production | |||||||
Crude oil (bbls/d) | 123 | 153 | (20%) | ||||
Activity | |||||||
Capital expenditures | 2,744 | 637 | 331% | ||||
Gross wells drilled | 1.00 | - | |||||
Net wells drilled | 1.00 | - | |||||
Activity review
Sales
Royalties
Operating expense
General and administration
CORPORATE
Overview
Financial review
Three Months Ended | Six Months Ended | ||||||||
Jun 30, | Mar 31, | Jun 30, | Jun 30, | Jun 30, | |||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | ||||
General and administration | 500 | 957 | (2,574) | 1,457 | (6,325) | ||||
Current income taxes | (547) | (377) | (378) | (924) | (551) | ||||
Interest expense | (14,550) | (13,298) | (12,334) | (27,848) | (23,794) | ||||
Realized gain on derivatives | 3,081 | 6,257 | 2,419 | 9,338 | 5,059 | ||||
Realized foreign exchange (loss) gain | (2,740) | 3,306 | 587 | 566 | (1,454) | ||||
Realized other income | 204 | 222 | 74 | 426 | 295 | ||||
Fund flows from operations | (14,052) | (2,933) | (12,206) | (16,985) | (26,770) | ||||
General and administration
Current income taxes
Interest expense
Hedging
FINANCIAL PERFORMANCE REVIEW
Three Months Ended | |||||||||||
Jun 30, | Mar 31, | Dec 31, | Sep 30, | Jun 30, | Mar 31, | Dec 31, | Sep 30, | ||||
($M except per share) | 2015 | 2015 | 2014 | 2014 | 2014 | 2014 | 2013 | 2013 | |||
Petroleum and natural gas sales | 264,331 | 195,885 | 306,073 | 344,688 | 387,684 | 381,183 | 325,108 | 327,185 | |||
Net earnings | 6,813 | 1,275 | 58,642 | 53,903 | 53,993 | 102,788 | 101,510 | 67,796 | |||
Net earnings per share | |||||||||||
Basic | 0.06 | 0.01 | 0.55 | 0.50 | 0.51 | 1.00 | 1.00 | 0.67 | |||
Diluted | 0.06 | 0.01 | 0.54 | 0.50 | 0.50 | 0.99 | 0.98 | 0.66 | |||
The following table shows a reconciliation of the change in net earnings:
($M) | Q2/15 vs. Q1/15 | Q2/15 vs. Q2/14 | 2015 vs. 2014 |
Net earnings - Comparative period | 1,275 | 53,993 | 156,781 |
Changes in: | |||
Fund flows from operations | 8,701 | (86,580) | (171,148) |
Equity based compensation | 1,154 | 331 | (2,237) |
Unrealized gain or loss on derivative instruments | 24,075 | 5,626 | (18,279) |
Unrealized foreign exchange gain or loss | 9,876 | 28,777 | 1,932 |
Unrealized other expense | 57 | (308) | (315) |
Accretion | (38) | 237 | 274 |
Depletion and depreciation | (20,189) | (6,244) | 2,251 |
Deferred tax | (18,098) | 10,981 | 38,829 |
Net earnings - Current period | 6,813 | 6,813 | 8,088 |
The fluctuations in net earnings from quarter-to-quarter and from year-to-year are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations and include: sales, royalties, operating expenses, transportation, general and administration expense, current tax expense, interest expense, realized gains and losses on derivative instruments, and realized foreign exchange gains and losses. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include amounts resulting from acquisitions or charges resulting from impairment or impairment recoveries.
Equity based compensation
Equity based compensation expense relates to non-cash compensation
expense attributable to long-term incentives granted to directors,
officers, and employees under the Vermilion Incentive Plan ("VIP"). The
expense is recognized over the vesting period based on the grant date
fair value of awards, adjusted for the ultimate number of awards that
actually vest as determined by the Company's achievement of performance
conditions.
Equity based compensation expense in Q2 2015 was lower than Q1 2015 as a result of awards that vested during Q2 2015 with higher actual performance conditions. For the six months ended June 30, 2015, equity based compensation expense was higher versus the comparable period due to a higher number of awards outstanding.
Unrealized gain or loss on derivative instruments
Unrealized gain or loss on derivative instruments arise as a result of
changes in forecasted future commodity prices. As Vermilion uses
derivative instruments to manage the commodity price exposure of our
future crude oil and natural gas production, we will normally recognize
unrealized gains on derivative instruments when forecasted future
commodity prices decline and vice-versa.
For the six months ended June 30, 2015, we recognized an unrealized loss on derivative instruments of $15.9 million, relating primarily to our TTF, Dated Brent, and WTI swaps and collars. As at June 30, 2015, we have a net derivative asset position of $8.9 million.
Unrealized foreign exchange gain or loss
As a result of Vermilion's international operations, Vermilion conducts
business in currencies other than the Canadian dollar and has monetary
assets and liabilities (including cash, receivables, payables,
derivative assets and liabilities, and intercompany loans) denominated
in such currencies. Vermilion's exposure to foreign currencies
includes the US dollar, the Euro and the Australian Dollar.
Unrealized foreign exchange gains and losses are the result of translating monetary assets and liabilities held in non-functional currencies to the respective functional currencies of Vermilion and its subsidiaries. Unrealized foreign exchange primarily results from the translation of Euro denominated financial assets. As such, an appreciation in the Euro against the Canadian dollar will result in an unrealized foreign exchange gain, and vice-versa.
For the three months ended June 30, 2015, the Canadian dollar weakened versus the Euro and the US dollar, resulting in an unrealized foreign exchange gain of $5.0 million. For the six months ended June 30, 2015, the foreign exchange gain of $0.2 million was driven by a significant weakening of the Canadian dollar against the US dollar, offset by a slight strengthening of the Canadian dollar relative to the Euro.
Accretion
Fluctuations in accretion expense are primarily the result of changes in
discount rates applicable to the balance of asset retirement
obligations and additions resulting from drilling and acquisitions.
Q2 2015 accretion expense was relatively consistent with all comparative periods.
Depletion and depreciation
Fluctuations in depletion and depreciation expense are primarily the
result of changes in produced crude oil and natural gas volumes.
Depletion and depreciation on a per boe basis for Q2 2015 of $22.98 was slightly higher as compared to $21.90 and $22.45 in Q1 2015 and Q2 2014, respectively. The increase is due to increased production from light crude oil properties in Saskatchewan, Canada which has higher per boe depletion expense, and decreased production from natural gas properties in Drayton Valley, Canada and in the Netherlands, which have lower per boe depletion expense. On a year-over-year basis, depletion and depreciation on a per boe decreased to $22.48 per boe for the six months ended June 30, 2015, as compared to $22.78 in the comparable period in the prior year. This decrease is primarily due to lower production in the Cardium light crude oil resource play in Canada and in Australia, which experience higher per boe amounts.
Deferred tax
Deferred tax expense arises primarily as a result of changes in the
accounting basis and tax basis for capital assets and asset retirement
obligations and changes in available tax losses.
FINANCIAL POSITION REVIEW
Balance sheet strategy
We believe that our balance sheet supports our defined growth
initiatives and our focus is on managing and maintaining a conservative
balance sheet. To ensure that our balance sheet continues to support
our defined growth initiatives, we regularly review whether forecasted
fund flows from operations is sufficient to finance planned capital
expenditures, dividends, and abandonment and reclamation expenditures.
To the extent that forecasted fund flows from operations is not
expected to be sufficient to fulfill such expenditures, we will
evaluate our ability to finance any excess with debt (including
borrowing using the unutilized capacity of our existing revolving
credit facility) or issue equity.
To ensure that we maintain a conservative balance sheet, we monitor the ratio of net debt to fund flows from operations and typically strive to maintain an internally targeted ratio of approximately 1.0 to 1.3 in a normalized commodity price environment. Where prices trend higher, we may target a lower ratio and conversely, in a lower commodity price environment, the acceptable ratio may be higher. At times, we will use our balance sheet to finance acquisitions and, in these situations, we are prepared to accept a higher ratio in the short term but will implement a strategy to reduce the ratio to acceptable levels within a reasonable period of time, usually considered to be no more than 12 to 24 months. This plan could potentially include an increase in hedging activities, a reduction in capital expenditures, an issuance of equity or the utilization of excess fund flows from operations to reduce outstanding indebtedness.
In the current low commodity price environment, Vermilion's net debt to fund flows ratio is expected to be higher than the longer term target ratio. During this period, Vermilion will remain focused on maintaining a strong balance sheet and will manage its business accordingly.
Long-term debt
Our long-term debt consists of our revolving credit facility and our
senior unsecured notes. The applicable annual interest rates and the
balances recognized on our balance sheet are as follows:
Annual Interest Rate | As at | ||||||||
Jun 30, | Dec 31, | Jun 30, | Dec 31, | ||||||
($M) | 2015 | 2014 | 2015 | 2014 | |||||
Revolving credit facility | 3.0% | 3.1% | 1,200,077 | 1,014,067 | |||||
Senior unsecured notes (1) | 6.5% | 6.5% | 224,457 | 224,013 | |||||
Long-term debt | 3.6% | 3.8% | 1,424,534 | 1,238,080 |
(1) |
The senior unsecured notes, which will mature on February 10, 2016, are included in the current portion of long-term debt as at June 30, 2015. |
Revolving Credit Facility
On January 30, 2015, Vermilion increased its credit facility from $1.5
billion to $1.75 billion. During Q2 2015, we negotiated a further
expansion and extension of our existing revolving credit facilities
from $1.75 billion to $2 billion with a maturity of May 2019. The
facility bears interest at rates applicable to demand loans plus
applicable margins. The following table outlines the terms of our
revolving credit facility:
As at | ||||||||
Jun 30, | Dec 31, | |||||||
2015 | 2014 | |||||||
Total facility amount | $2.0 billion | $1.5 billion | ||||||
Amount drawn | $1.2 billion | $1.0 billion | ||||||
Letters of credit outstanding | $26.5 million | $8.6 million | ||||||
Facility maturity date | 31-May-19 | 31-May-17 | ||||||
In addition, the revolving credit facility is subject to the following covenants:
As at | ||||||||||
Jun 30, | Dec 31, | |||||||||
Financial covenant | Limit | 2015 | 2014 | |||||||
Consolidated total debt to consolidated EBITDA | 4.0 | 1.84 | 1.21 | |||||||
Consolidated total senior debt to consolidated EBITDA | 3.0 | 1.52 | 0.99 | |||||||
Consolidated total senior debt to total capitalization | 50% | 35% | 31% | |||||||
Our covenants include financial measures defined within our revolving credit facility agreement that are not defined under GAAP. These financial measures are defined by our revolving credit facility agreement as follows:
Vermilion was in compliance with its financial covenants for all periods presented.
Senior Unsecured Notes
We have outstanding senior unsecured notes that are senior unsecured
obligations and rank pari passu with all our other present and future
unsecured and unsubordinated indebtedness. The following table
outlines the terms of these notes:
Total issued and outstanding amount | $225.0 million | |||||
Interest rate | 6.5% per annum | |||||
Issued date | February 10, 2011 | |||||
Maturity date | February 10, 2016 | |||||
Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest. The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.
Net debt
Net debt is reconciled to its most directly comparable GAAP measure,
long-term debt, as follows:
As at | |||||||
Jun 30, | Dec 31, | ||||||
($M) | 2015 | 2014 | |||||
Long-term debt | 1,200,077 | 1,238,080 | |||||
Current liabilities(1) | 479,848 | 365,729 | |||||
Current assets | (302,023) | (338,159) | |||||
Net debt | 1,377,902 | 1,265,650 | |||||
Ratio of net debt to annualized fund flows from operations | 2.8 | 1.6 |
(1) |
Includes the current portion of long-term debt, which, as at June 30,
2015, represents the senior unsecured notes that will mature on February 10, 2016. |
Long term debt, including the current portion, as at June 30, 2015 increased to $1.42 billion from $1.24 billion as at December 31, 2014 as a result of draws on the revolving credit facility during the current year to fund capital expenditures, particularly relating to development expenditures in Canada and Ireland. The increase in long-term debt resulted in an increase to net debt from $1.27 billion to $1.38 billion. As a result of this increase to long-term debt and weak commodity prices, the ratio of net debt to fund flows from operations increased from 1.6 times as at December 31, 2014 to 2.8 times for the six months ended June 30, 2015.
Shareholders' capital
During the six months ended June 30, 2015, we maintained monthly
dividends at $0.215 per share and declared dividends which totalled
$140.4 million.
The following table outlines our dividend payment history:
Date | Monthly dividend per unit or share | |||||
January 2003 to December 2007 | $0.170 | |||||
January 2008 to December 2012 | $0.190 | |||||
January 2013 to December 31, 2013 | $0.200 | |||||
January 2014 to Present | $0.215 | |||||
Our policy with respect to dividends is to be conservative and maintain a low ratio of dividends to fund flows from operations. During low commodity price cycles, we will initially maintain dividends and allow the ratio to rise. Should low commodity price cycles remain for an extended period of time, we will evaluate the necessity of changing the level of dividends, taking into consideration capital development requirements, debt levels and acquisition opportunities. In a further step to preserve our financial flexibility and conservatively exercise our access to capital, an amendment to our existing DRIP to include a Premium Dividend™ Component was announced in February 2015. The Premium Dividend™ Component, when combined with our continuing Dividend Reinvestment Component, increases our access to the lowest cost sources of equity capital available. While the Premium Dividend™ results in a modest amount of equity issuance, we believe it represents the most prudent approach to preserving near-term balance sheet strength. We view implementation of a Premium Dividend™ as a short-term measure to maintain our financial flexibility while we continue to lower our unit costs and await further clarity on the direction of commodity prices. Both components of our program can be turned off at the company's discretion, offering considerable flexibility. We will actively monitor our ongoing needs and manage our continued use of each component as circumstances dictate. It is not currently expected that Vermilion will be required to change its dividend in 2015.
Although we currently expect to be able to maintain our current dividend, fund flows from operations may not be sufficient during this period to fund cash dividends, capital expenditures and asset retirement obligations. We will evaluate our ability to finance any shortfalls with debt, issuances of equity or by reducing some or all categories of expenditures to ensure that total expenditures do not exceed available funds.
The following table reconciles the change in shareholders' capital:
Shareholders' Capital | Number of Shares ('000s) | Amount ($M) | |||
Balance as at December 31, 2014 | 107,303 | 1,959,021 | |||
Issuance of shares pursuant to the dividend reinvestment and Premium DividendTM plans | 1,195 | 63,679 | |||
Vesting of equity based awards | 1,158 | 56,855 | |||
Share-settled dividends on vested equity based awards | 135 | 7,561 | |||
Shares issued pursuant to the employee savings and bonus plans | 15 | 816 | |||
Balance as at June 30, 2015 | 109,806 | 2,087,932 |
As at June 30, 2015, there were approximately 1.7 million VIP awards outstanding. As at August 6, 2015, there were approximately 110.1 million common shares issued and outstanding.
ASSET RETIREMENT OBLIGATIONS
As at June 30, 2015, asset retirement obligations were $351.3 million compared to $350.8 million as at December 31, 2014.
The slight increase in asset retirement obligations is largely attributable to accretion and additions from new wells drilled year-to-date, offset by an overall increase in the discount rates applied to the abandonment obligations.
OFF BALANCE SHEET ARRANGEMENTS
We have certain lease agreements that are entered into in the normal course of operations, including operating leases for which no asset or liability value has been assigned to the consolidated balance sheet as at June 30, 2015.
We have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.
RISK MANAGEMENT
Vermilion is exposed to various market and operational risks. For a detailed discussion of these risks, please see Vermilion's Annual Report for the year ended December 31, 2014.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with IFRS requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on Vermilion's consolidated financial statements. Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions. There have been no material changes to our critical accounting estimates used in applying accounting policies for the six months ended June 30, 2015. Further information, including a discussion of critical accounting estimates, can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2014, available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
INTERNAL CONTROL OVER FINANCIAL REPORTING
There was no change in Vermilion's internal control over financial reporting that occurred during the period covered by this MD&A that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Supplemental Table 1: Netbacks
The following table includes financial statement information on a per unit basis by business unit. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.
Three Months Ended June 30, 2015 | Six Months Ended June 30, 2015 |
Three Months Ended June 30, 2014 |
Six Months Ended June 30, 2014 |
|||||||||||||||||||||
Oil & NGLs | Natural Gas | Total | Oil & NGLs | Natural Gas | Total | Total | Total | |||||||||||||||||
$/bbl | $/mcf | $/boe | $/bbl | $/mcf | $/boe | $/boe | $/boe | |||||||||||||||||
Canada | ||||||||||||||||||||||||
Sales | 59.06 | 2.78 | 40.59 | 54.14 | 2.88 | 38.24 | 71.56 | 70.55 | ||||||||||||||||
Royalties | (5.31) | 0.17 | (2.56) | (5.59) | (0.03) | (3.25) | (7.99) | (7.61) | ||||||||||||||||
Transportation | (2.67) | (0.18) | (1.99) | (2.55) | (0.17) | (1.90) | (1.76) | (1.75) | ||||||||||||||||
Operating | (10.53) | (1.39) | (9.58) | (9.78) | (1.40) | (9.19) | (9.28) | (9.31) | ||||||||||||||||
Operating netback | 40.55 | 1.38 | 26.46 | 36.22 | 1.28 | 23.90 | 52.53 | 51.88 | ||||||||||||||||
General and administration | (2.45) | (2.15) | (2.88) | (2.32) | ||||||||||||||||||||
Fund flows from operations netback | 24.01 | 21.75 | 49.65 | 49.56 | ||||||||||||||||||||
France | ||||||||||||||||||||||||
Sales | 72.83 | 1.53 | 71.96 | 68.97 | 1.53 | 68.52 | 117.29 | 117.41 | ||||||||||||||||
Royalties | (5.92) | (0.01) | (5.84) | (5.72) | (0.01) | (5.68) | (7.34) | (7.34) | ||||||||||||||||
Transportation | (3.15) | - | (3.11) | (3.19) | - | (3.17) | (5.07) | (4.91) | ||||||||||||||||
Operating | (10.72) | (1.16) | (10.67) | (11.14) | (1.16) | (11.11) | (15.58) | (15.98) | ||||||||||||||||
Operating netback | 53.04 | 0.36 | 52.34 | 48.92 | 0.36 | 48.56 | 89.30 | 89.18 | ||||||||||||||||
General and administration | (4.30) | (4.84) | (5.24) | (5.21) | ||||||||||||||||||||
Other income | - | 15.39 | - | - | ||||||||||||||||||||
Current income taxes | (8.21) | (11.43) | (23.30) | (24.25) | ||||||||||||||||||||
Fund flows from operations netback | 39.83 | 47.68 | 60.76 | 59.72 | ||||||||||||||||||||
Netherlands | ||||||||||||||||||||||||
Sales | 53.28 | 7.92 | 47.63 | 53.15 | 8.01 | 48.13 | 48.14 | 56.06 | ||||||||||||||||
Royalties | - | (0.44) | (2.58) | - | (0.36) | (2.11) | (1.12) | (2.28) | ||||||||||||||||
Operating | - | (1.83) | (10.78) | - | (1.80) | (10.66) | (10.29) | (9.76) | ||||||||||||||||
Operating netback | 53.28 | 5.65 | 34.27 | 53.15 | 5.85 | 35.36 | 36.73 | 44.02 | ||||||||||||||||
General and administration | (0.90) | (1.13) | (0.53) | (0.73) | ||||||||||||||||||||
Current income taxes | (4.67) | (4.49) | (2.10) | (3.99) | ||||||||||||||||||||
Fund flows from operations netback | 28.70 | 29.74 | 34.10 | 39.30 | ||||||||||||||||||||
Germany | ||||||||||||||||||||||||
Sales | - | 7.22 | 43.31 | - | 7.38 | 44.27 | 45.36 | 49.50 | ||||||||||||||||
Royalties | - | (1.52) | (9.12) | - | (1.29) | (7.71) | (9.34) | (10.11) | ||||||||||||||||
Transportation | - | (0.84) | (5.05) | - | (0.72) | (4.29) | (4.30) | (3.65) | ||||||||||||||||
Operating | - | (0.93) | (5.60) | - | (1.13) | (6.78) | (8.35) | (8.90) | ||||||||||||||||
Operating netback | - | 3.93 | 23.54 | - | 4.24 | 25.49 | 23.37 | 26.84 | ||||||||||||||||
General and administration | (5.85) | (6.12) | (3.39) | (3.46) | ||||||||||||||||||||
Current income taxes | - | - | (2.07) | (2.58) | ||||||||||||||||||||
Fund flows from operations netback | 17.69 | 19.37 | 17.91 | 20.80 | ||||||||||||||||||||
Australia | ||||||||||||||||||||||||
Sales | 80.87 | - | 80.87 | 81.60 | - | 81.60 | 126.87 | 127.11 | ||||||||||||||||
Operating | (26.02) | - | (26.02) | (25.91) | - | (25.91) | (25.99) | (25.12) | ||||||||||||||||
PRRT (1) | (4.85) | - | (4.85) | (6.19) | - | (6.19) | (27.39) | (28.14) | ||||||||||||||||
Operating netback | 50.00 | - | 50.00 | 49.50 | - | 49.50 | 73.49 | 73.85 | ||||||||||||||||
General and administration | (1.64) | (2.81) | (3.58) | (2.45) | ||||||||||||||||||||
Corporate income taxes | (7.39) | (6.17) | (12.27) | (12.41) | ||||||||||||||||||||
Fund flows from operations netback | 40.97 | 40.52 | 57.64 | 58.99 | ||||||||||||||||||||
United States | ||||||||||||||||||||||||
Sales | 60.57 | - | 60.57 | 54.07 | - | 54.07 | - | - | ||||||||||||||||
Royalties | (17.08) | - | (17.08) | (15.92) | - | (15.92) | - | - | ||||||||||||||||
Operating | (9.88) | - | (9.88) | (13.04) | - | (13.04) | - | - | ||||||||||||||||
Operating netback | 33.61 | - | 33.61 | 25.11 | - | 25.11 | - | - | ||||||||||||||||
General and administration | (86.12) | (81.87) | - | - | ||||||||||||||||||||
Fund flows from operations netback | (52.51) | (56.76) | - | - | ||||||||||||||||||||
Total Company | ||||||||||||||||||||||||
Sales | 68.90 | 4.86 | 54.65 | 64.23 | 5.06 | 51.19 | 82.96 | 85.70 | ||||||||||||||||
Realized hedging (loss) gain | (0.13) | 0.33 | 0.64 | 0.26 | 0.38 | 1.04 | 0.52 | 0.56 | ||||||||||||||||
Royalties | (4.37) | (0.25) | (3.33) | (4.73) | (0.31) | (3.62) | (6.21) | (5.91) | ||||||||||||||||
Transportation | (2.23) | (0.38) | (2.25) | (2.34) | (0.36) | (2.27) | (2.57) | (2.44) | ||||||||||||||||
Operating | (14.03) | (1.45) | (12.12) | (12.97) | (1.48) | (11.40) | (12.46) | (12.95) | ||||||||||||||||
PRRT (1) | (1.09) | - | (0.70) | (1.03) | - | (0.64) | (2.72) | (3.67) | ||||||||||||||||
Operating netback | 47.05 | 3.11 | 36.89 | 43.42 | 3.29 | 34.30 | 59.52 | 61.29 | ||||||||||||||||
General and administration | (3.00) | (3.12) | (3.80) | (3.59) | ||||||||||||||||||||
Interest expense | (3.01) | (3.10) | (2.64) | (2.65) | ||||||||||||||||||||
Realized foreign exchange (loss) gain | (0.57) | 0.06 | 0.12 | (0.16) | ||||||||||||||||||||
Other income | 0.04 | 3.58 | 0.02 | 0.03 | ||||||||||||||||||||
Corporate income taxes (1) | (3.59) | (3.89) | (6.98) | (7.94) | ||||||||||||||||||||
Fund flows from operations netback | 26.76 | 27.83 | 46.24 | 46.98 |
(1) |
Vermilion considers Australian PRRT to be an operating item and
accordingly has included PRRT in the calculation of operating
netbacks. Current income taxes presented above excludes PRRT. |
Supplemental Table 2: Hedges
The following tables outline Vermilion's outstanding risk management positions as at June 30, 2015:
Note | Volume | Strike Price(s) | |||||||
Crude Oil | |||||||||
WTI - Collar | |||||||||
July 2015 - September 2015 | 1 | 250 bbl/d | 60.00 - 68.60 US $ | ||||||
July 2015 - October 2015 | 1 | 250 bbl/d | 60.00 - 72.40 US $ | ||||||
July 2015 - December 2015 | 2 | 750 bbl/d | 75.00 - 82.60 CAD $ | ||||||
July 2015 - December 2015 | 1 | 250 bbl/d | 61.00 - 69.75 US $ | ||||||
July 2015 - March 2016 | 3 | 250 bbl/d | 75.00 - 83.45 CAD $ | ||||||
July 2015 - June 2016 | 4 | 500 bbl/d | 75.50 - 85.08 CAD $ | ||||||
October 2015 - December 2015 | 3 | 250 bbl/d | 70.00 - 82.95 CAD $ | ||||||
WTI - Swap | |||||||||
July 2015 - September 2015 | 5 | 250 bbl/d | 75.71 CAD $ | ||||||
MSW - Fixed Price Differential | |||||||||
July 2015 - September 2015 | 250 bbl/d | WTI less 2.65 US $ | |||||||
Dated Brent - Collar | |||||||||
April 2015 - September 2015 | 1 | 250 bbl/d | 60.00 - 74.15 US $ | ||||||
July 2015 - September 2015 | 1 | 250 bbl/d | 65.00 - 75.05 US $ | ||||||
July 2015 - October 2015 | 6 | 250 bbl/d | 65.00 - 74.40 US $ | ||||||
July 2015 - June 2016 | 7 | 1,000 bbl/d | 80.50 - 93.49 CAD $ | ||||||
July 2015 - June 2016 | 8 | 500 bbl/d | 64.50 - 75.48 US $ | ||||||
October 2015 - December 2015 | 9 | 1,000 bbl/d | 79.38 - 92.45 CAD $ | ||||||
October 2015 - June 2016 | 10 | 250 bbl/d | 82.00 - 94.55 CAD $ | ||||||
January 2016 - June 2016 | 3 | 250 bbl/d | 84.00 - 93.70 CAD $ |
(1) |
The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price. |
(2) |
The contracted volumes increase to 1,500 boe/d for any monthly
settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(3) |
The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(4) |
The contracted volumes increase to 1,250 boe/d for any monthly
settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(5) |
The contract is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(6) |
The contracted volumes increase to 500 boe/d for any monthly settlement periods above the contracted ceiling price. |
(7) |
The contracted volumes increase to 2,500 boe/d for any monthly
settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(8) |
The contracted volumes increase to 1,000 boe/d for any monthly
settlement periods above the contracted ceiling price. |
(9) |
The contracted volumes increase to 2,000 boe/d for any monthly
settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
(10) |
The contracted volumes increase to 750 boe/d for any monthly settlement periods above the contracted ceiling price and is settled on the monthly average price (monthly average US$/bbl multiplied by the Bank of Canada monthly average noon day rate). |
Note | Volume | Strike Price(s) | |||||||||
North American Natural Gas | |||||||||||
AECO - Collar | |||||||||||
April 2015 - October 2015 | 2,500 GJ/d | 2.75 - 3.52 CAD $ | |||||||||
April 2015 - December 2015 | 2,500 GJ/d | 2.75 - 3.52 CAD $ | |||||||||
October 2015 - December 2015 | 2,500 GJ/d | 2.55 - 3.19 CAD $ | |||||||||
November 2015 - March 2016 | 2,500 GJ/d | 2.50 - 3.76 CAD $ | |||||||||
January 2016 - December 2016 | 7,500 GJ/d | 2.53 - 3.34 CAD $ | |||||||||
April 2016 - October 2016 | 2,500 GJ/d | 2.50 - 2.88 CAD $ | |||||||||
AECO - Swap | |||||||||||
April 2015 - October 2015 | 1 | 10,000 GJ/d | 2.98 CAD $ | ||||||||
April 2015 - December 2015 | 2 | 2,500 GJ/d | 2.99 CAD $ | ||||||||
AECO Basis - Fixed Price Differential | |||||||||||
January 2015 - December 2015 | 5,000 mmbtu/d | Nymex HH less 0.68 US $ | |||||||||
April 2015 - October 2015 | 7,500 mmbtu/d | Nymex HH less 0.62 US $ | |||||||||
Nymex HH - Collar | |||||||||||
April 2015 - October 2015 | 10,000 mmbtu/d | 3.36 - 4.01 US $ | |||||||||
April 2015 - December 2015 | 2,500 mmbtu/d | 3.50 - 4.11 US $ | |||||||||
November 2015 - March 2016 | 3 | 5,000 mmbtu/d | 3.25 - 3.86 US $ | ||||||||
European Natural Gas | |||||||||||
NBP - Swap | |||||||||||
July 2015 - March 2016 | 2,592 GJ/d | 6.42 EUR € | |||||||||
October 2015 - March 2016 | 10,368 GJ/d | 6.54 EUR € | |||||||||
January 2016 - June 2016 | 5,184 GJ/d | 6.24 EUR € | |||||||||
January 2016 - June 2016 | 2,592 GJ/d | 6.82 US $ | |||||||||
TTF - Collar | |||||||||||
January 2015 - December 2015 | 2,592 GJ/d | 6.11 - 6.83 EUR € | |||||||||
April 2016 - December 2016 | 7,776 GJ/d | 5.56 - 6.16 EUR € | |||||||||
TTF - Swap | |||||||||||
January 2015 - December 2015 | 11,664 GJ/d | 6.45 EUR € | |||||||||
January 2015 - March 2016 | 5,184 GJ/d | 6.40 EUR € | |||||||||
January 2015 - June 2016 | 2,592 GJ/d | 6.07 EUR € | |||||||||
February 2015 - March 2016 | 5,184 GJ/d | 6.24 EUR € | |||||||||
April 2015 - December 2015 | 2,592 GJ/d | 6.30 EUR € | |||||||||
April 2015 - March 2016 | 5,832 GJ/d | 6.18 EUR € | |||||||||
October 2015 - December 2015 | 2,592 GJ/d | 5.69 EUR € | |||||||||
October 2015 - March 2016 | 2,592 GJ/d | 6.64 EUR € | |||||||||
January 2016 - June 2016 | 2,592 GJ/d | 6.10 EUR € | |||||||||
April 2016 - December 2016 | 2,592 GJ/d | 5.91 EUR € | |||||||||
Electricity | |||||||||||
AESO - Swap | |||||||||||
January 2016 - December 2016 | 62.4 MWh/d | 37.13 CAD $ | |||||||||
AESO - Swap (Physical) | |||||||||||
January 2013 - December 2015 | 72.0 MWh/d | 53.17 CAD $ | |||||||||
US Dollar | |||||||||||
USD - Collar | |||||||||||
February 2015 - December 2015 | 2,500,000 US $/month | 1.180 - 1.223 CAD $ | |||||||||
USD - Forward | |||||||||||
February 2015 - December 2015 | 2,500,000 US $/month | 1.198 CAD $ |
(1) |
On the last business day of each month, the counterparty has the option
to increase the contracted volumes by an additional 10,000 GJ/d at the contracted price, for the following month. |
(2) |
On the last business day of each month, the counterparty has the option
to increase the contracted volumes by an additional 2,500 GJ/d at the contracted price, for the following month. |
(3) |
The contracted volumes increase to 10,000 mmbtu/d for any monthly
settlement periods above the contracted ceiling price. |
Supplemental Table 3: Capital Expenditures
Three Months Ended | Six Months Ended | |||||||||||||||
By classification | Jun 30, | Mar 31, | Jun 30, | Jun 30, | Jun 30, | |||||||||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||||
Drilling and development | 90,173 | 174,311 | 117,975 | 264,484 | 286,815 | |||||||||||
Exploration and evaluation | - | - | 17,098 | - | 44,633 | |||||||||||
Capital expenditures | 90,173 | 174,311 | 135,073 | 264,484 | 331,448 | |||||||||||
Property acquisition | 480 | 35 | - | 515 | 178,227 | |||||||||||
Corporate acquisition | - | - | 381,139 | - | 381,139 | |||||||||||
Acquisitions | 480 | 35 | 381,139 | 515 | 559,366 | |||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
By category | Jun 30, | Mar 31, | Jun 30, | Jun 30, | Jun 30, | |||||||||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||||
Land | 1,469 | 742 | 950 | 2,211 | 5,703 | |||||||||||
Seismic | 1,723 | 1,493 | 1,869 | 3,216 | 5,301 | |||||||||||
Drilling and completion | 31,976 | 82,343 | 42,083 | 114,319 | 148,619 | |||||||||||
Production equipment and facilities | 43,957 | 74,755 | 60,547 | 118,712 | 129,302 | |||||||||||
Recompletions | 9,288 | 7,115 | 13,459 | 16,403 | 17,685 | |||||||||||
Other | 1,760 | 7,863 | 16,165 | 9,623 | 24,838 | |||||||||||
Capital expenditures | 90,173 | 174,311 | 135,073 | 264,484 | 331,448 | |||||||||||
Acquisitions | 480 | 35 | 381,139 | 515 | 559,366 | |||||||||||
Total capital expenditures and acquisitions | 90,653 | 174,346 | 516,212 | 264,999 | 890,814 | |||||||||||
Three Months Ended | Six Months Ended | |||||||||||||||
By country | Jun 30, | Mar 31, | Jun 30, | Jun 30, | Jun 30, | |||||||||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||||
Canada | 22,265 | 114,884 | 418,294 | 137,149 | 538,001 | |||||||||||
France | 16,793 | 34,114 | 37,614 | 50,907 | 75,581 | |||||||||||
Netherlands | 18,885 | 4,333 | 21,513 | 23,218 | 41,631 | |||||||||||
Germany | 3,231 | 968 | 630 | 4,199 | 173,697 | |||||||||||
Ireland | 20,267 | 12,955 | 27,221 | 33,222 | 43,457 | |||||||||||
Australia | 6,468 | 6,455 | 10,991 | 12,923 | 16,682 | |||||||||||
United States | 2,744 | 637 | - | 3,381 | - | |||||||||||
Corporate | - | - | (51) | - | 1,765 | |||||||||||
Total capital expenditures and acquisitions | 90,653 | 174,346 | 516,212 | 264,999 | 890,814 |
Supplemental Table 4: Production
Q2/15 | Q1/15 | Q4/14 | Q3/14 | Q2/14 | Q1/14 | Q4/13 | Q3/13 | Q2/13 | Q1/13 | Q4/12 | Q3/12 | ||||||||||||||||||||||||||||
Canada | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 10,182 | 10,893 | 11,384 | 11,469 | 12,676 | 9,437 | 8,719 | 7,969 | 8,885 | 7,966 | 7,983 | 7,322 | |||||||||||||||||||||||||||
NGLs (bbls/d) | 3,755 | 2,976 | 2,741 | 2,291 | 2,796 | 2,071 | 1,699 | 1,897 | 1,725 | 1,335 | 1,106 | 1,204 | |||||||||||||||||||||||||||
Natural gas (mmcf/d) | 64.66 | 61.78 | 58.36 | 57.07 | 57.59 | 49.53 | 41.43 | 43.40 | 43.69 | 41.04 | 31.41 | 35.54 | |||||||||||||||||||||||||||
Total (boe/d) | 24,713 | 24,165 | 23,851 | 23,272 | 25,070 | 19,763 | 17,322 | 17,099 | 17,892 | 16,140 | 14,323 | 14,449 | |||||||||||||||||||||||||||
% of consolidated | 48% | 48% | 49% | 47% | 49% | 42% | 43% | 41% | 42% | 41% | 40% | 40% | |||||||||||||||||||||||||||
France | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 12,746 | 11,463 | 11,133 | 11,111 | 11,025 | 10,771 | 11,131 | 11,625 | 10,390 | 10,330 | 9,843 | 9,767 | |||||||||||||||||||||||||||
Natural gas (mmcf/d) | 1.03 | - | - | - | - | - | - | 5.23 | 4.19 | 4.21 | 3.91 | 3.39 | |||||||||||||||||||||||||||
Total (boe/d) | 12,917 | 11,463 | 11,133 | 11,111 | 11,025 | 10,771 | 11,131 | 12,496 | 11,088 | 11,032 | 10,495 | 10,333 | |||||||||||||||||||||||||||
% of consolidated | 25% | 23% | 22% | 22% | 21% | 23% | 27% | 30% | 26% | 29% | 29% | 28% | |||||||||||||||||||||||||||
Netherlands | |||||||||||||||||||||||||||||||||||||||
NGLs (bbls/d) | 112 | 63 | 81 | 63 | 96 | 69 | 62 | 48 | 50 | 96 | 70 | 41 | |||||||||||||||||||||||||||
Natural gas (mmcf/d) | 32.43 | 36.41 | 31.35 | 38.07 | 40.35 | 43.15 | 37.53 | 28.78 | 38.52 | 36.91 | 33.03 | 34.59 | |||||||||||||||||||||||||||
Total (boe/d) | 5,517 | 6,132 | 5,306 | 6,407 | 6,822 | 7,260 | 6,318 | 4,845 | 6,470 | 6,248 | 5,574 | 5,806 | |||||||||||||||||||||||||||
% of consolidated | 11% | 12% | 11% | 13% | 13% | 16% | 15% | 12% | 15% | 16% | 15% | 16% | |||||||||||||||||||||||||||
Germany | |||||||||||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 16.18 | 16.80 | 17.71 | 15.38 | 16.13 | 10.64 | - | - | - | - | - | - | |||||||||||||||||||||||||||
Total (boe/d) | 2,696 | 2,801 | 2,952 | 2,563 | 2,689 | 1,773 | - | - | - | - | - | - | |||||||||||||||||||||||||||
% of consolidated | 5% | 6% | 6% | 5% | 5% | 4% | - | - | - | - | - | - | |||||||||||||||||||||||||||
Australia | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 5,865 | 5,672 | 6,134 | 6,567 | 6,483 | 7,110 | 6,189 | 7,070 | 7,363 | 5,287 | 5,873 | 5,958 | |||||||||||||||||||||||||||
% of consolidated | 11% | 11% | 12% | 13% | 12% | 15% | 15% | 17% | 17% | 14% | 16% | 16% | |||||||||||||||||||||||||||
United States | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 123 | 153 | 195 | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||
Consolidated | |||||||||||||||||||||||||||||||||||||||
Crude oil & NGLs (bbls/d) | 32,783 | 31,220 | 31,668 | 31,501 | 33,076 | 29,458 | 27,800 | 28,609 | 28,413 | 25,014 | 24,875 | 24,292 | |||||||||||||||||||||||||||
% of consolidated | 63% | 62% | 64% | 63% | 63% | 63% | 68% | 69% | 66% | 65% | 69% | 66% | |||||||||||||||||||||||||||
Natural gas (mmcf/d) | 114.29 | 115.00 | 107.42 | 110.52 | 114.08 | 103.32 | 78.96 | 77.41 | 86.40 | 82.16 | 68.34 | 73.52 | |||||||||||||||||||||||||||
% of consolidated | 37% | 38% | 36% | 37% | 37% | 37% | 32% | 31% | 34% | 35% | 31% | 34% | |||||||||||||||||||||||||||
Total (boe/d) | 51,831 | 50,386 | 49,571 | 49,920 | 52,089 | 46,677 | 40,960 | 41,510 | 42,813 | 38,707 | 36,265 | 36,546 | |||||||||||||||||||||||||||
YTD 2015 | 2014 | 2013 | 2012 | 2011 | 2010 | ||||||||||||||||||||||||||||||||||
Canada | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 10,535 | 11,248 | 8,387 | 7,659 | 4,701 | 2,778 | |||||||||||||||||||||||||||||||||
NGLs (bbls/d) | 3,367 | 2,476 | 1,666 | 1,232 | 1,297 | 1,427 | |||||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 63.23 | 55.67 | 42.39 | 37.50 | 43.38 | 43.91 | |||||||||||||||||||||||||||||||||
Total (boe/d) | 24,441 | 23,001 | 17,117 | 15,142 | 13,227 | 11,524 | |||||||||||||||||||||||||||||||||
% of consolidated | 48% | 47% | 41% | 40% | 38% | 36% | |||||||||||||||||||||||||||||||||
France | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 12,108 | 11,011 | 10,873 | 9,952 | 8,110 | 8,347 | |||||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 0.52 | - | 3.40 | 3.59 | 0.95 | 0.92 | |||||||||||||||||||||||||||||||||
Total (boe/d) | 12,194 | 11,011 | 11,440 | 10,550 | 8,269 | 8,501 | |||||||||||||||||||||||||||||||||
% of consolidated | 24% | 22% | 28% | 28% | 23% | 26% | |||||||||||||||||||||||||||||||||
Netherlands | |||||||||||||||||||||||||||||||||||||||
NGLs (bbls/d) | 88 | 77 | 64 | 67 | 58 | 35 | |||||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 34.41 | 38.20 | 35.42 | 34.11 | 32.88 | 28.31 | |||||||||||||||||||||||||||||||||
Total (boe/d) | 5,823 | 6,443 | 5,967 | 5,751 | 5,538 | 4,753 | |||||||||||||||||||||||||||||||||
% of consolidated | 11% | 13% | 15% | 15% | 16% | 15% | |||||||||||||||||||||||||||||||||
Germany | |||||||||||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 16.49 | 14.99 | - | - | - | - | |||||||||||||||||||||||||||||||||
Total (boe/d) | 2,748 | 2,498 | - | - | - | - | |||||||||||||||||||||||||||||||||
% of consolidated | 5% | 5% | - | - | - | - | |||||||||||||||||||||||||||||||||
Australia | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 5,769 | 6,571 | 6,481 | 6,360 | 8,168 | 7,354 | |||||||||||||||||||||||||||||||||
% of consolidated | 11% | 13% | 16% | 17% | 23% | 23% | |||||||||||||||||||||||||||||||||
United States | |||||||||||||||||||||||||||||||||||||||
Crude oil (bbls/d) | 138 | 49 | - | - | - | - | |||||||||||||||||||||||||||||||||
Consolidated | |||||||||||||||||||||||||||||||||||||||
Crude oil & NGLs (bbls/d) | 32,005 | 31,432 | 27,471 | 25,270 | 22,334 | 19,941 | |||||||||||||||||||||||||||||||||
% of consolidated | 63% | 63% | 67% | 67% | 63% | 62% | |||||||||||||||||||||||||||||||||
Natural gas (mmcf/d) | 114.64 | 108.85 | 81.21 | 75.20 | 77.21 | 73.14 | |||||||||||||||||||||||||||||||||
% of consolidated | 37% | 37% | 33% | 33% | 37% | 38% | |||||||||||||||||||||||||||||||||
Total (boe/d) | 51,113 | 49,573 | 41,005 | 37,803 | 35,202 | 32,132 |
Supplemental Table 5: Segmented Financial Results
Three Months Ended June 30, 2015 | |||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia | United States | Corporate | Total | ||||||||
Drilling and development | 21,881 | 16,697 | 18,885 | 3,231 | 20,267 | 6,468 | 2,744 | - | 90,173 | ||||||||
Oil and gas sales to external customers | 91,284 | 81,627 | 23,913 | 10,626 | - | 56,204 | 677 | - | 264,331 | ||||||||
Royalties | (5,768) | (6,620) | (1,294) | (2,238) | - | - | (191) | - | (16,111) | ||||||||
Revenue from external customers | 85,516 | 75,007 | 22,619 | 8,388 | - | 56,204 | 486 | - | 248,220 | ||||||||
Transportation expense | (4,469) | (3,526) | - | (1,240) | (1,648) | - | - | - | (10,883) | ||||||||
Operating expense | (21,534) | (12,102) | (5,414) | (1,373) | - | (18,083) | (110) | - | (58,616) | ||||||||
General and administration | (5,510) | (4,874) | (454) | (1,435) | (628) | (1,141) | (963) | 500 | (14,505) | ||||||||
PRRT | - | - | - | - | - | (3,371) | - | - | (3,371) | ||||||||
Corporate income taxes | - | (9,316) | (2,347) | - | - | (5,134) | - | (547) | (17,344) | ||||||||
Interest expense | - | - | - | - | - | - | - | (14,550) | (14,550) | ||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 3,081 | 3,081 | ||||||||
Realized foreign exchange loss | - | - | - | - | - | - | - | (2,740) | (2,740) | ||||||||
Realized other income | - | - | - | - | - | - | - | 204 | 204 | ||||||||
Fund flows from operations | 54,003 | 45,189 | 14,404 | 4,340 | (2,276) | 28,475 | (587) | (14,052) | 129,496 | ||||||||
Six Months Ended June 30, 2015 | |||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia | United States | Corporate | Total | ||||||||
Total assets | 1,931,640 | 854,608 | 211,587 | 163,069 | 856,739 | 233,956 | 18,785 | 158,430 | 4,428,814 | ||||||||
Drilling and development | 136,730 | 50,811 | 23,218 | 4,199 | 33,222 | 12,923 | 3,381 | - | 264,484 | ||||||||
Oil and gas sales to external customers | 169,168 | 141,459 | 50,731 | 22,021 | - | 75,488 | 1,349 | - | 460,216 | ||||||||
Royalties | (14,360) | (11,722) | (2,220) | (3,836) | - | - | (397) | - | (32,535) | ||||||||
Revenue from external customers | 154,808 | 129,737 | 48,511 | 18,185 | - | 75,488 | 952 | - | 427,681 | ||||||||
Transportation expense | (8,411) | (6,537) | - | (2,134) | (3,341) | - | - | - | (20,423) | ||||||||
Operating expense | (40,633) | (22,928) | (11,240) | (3,372) | - | (23,969) | (325) | - | (102,467) | ||||||||
General and administration | (9,525) | (9,985) | (1,191) | (3,043) | (1,140) | (2,595) | (2,043) | 1,457 | (28,065) | ||||||||
PRRT | - | - | - | - | - | (5,725) | - | - | (5,725) | ||||||||
Corporate income taxes | - | (23,597) | (4,735) | - | - | (5,711) | - | (924) | (34,967) | ||||||||
Interest expense | - | - | - | - | - | - | - | (27,848) | (27,848) | ||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 9,338 | 9,338 | ||||||||
Realized foreign exchange gain | - | - | - | - | - | - | - | 566 | 566 | ||||||||
Realized other income | - | 31,775 | - | - | - | - | - | 426 | 32,201 | ||||||||
Fund flows from operations | 96,239 | 98,465 | 31,345 | 9,636 | (4,481) | 37,488 | (1,416) | (16,985) | 250,291 |
ADDITIONAL AND NON-GAAP FINANCIAL MEASURES
This MD&A includes references to certain financial measures which do not have standardized meanings prescribed by IFRS. As such, these financial measures are considered additional GAAP or non-GAAP financial measures and therefore may not be comparable with similar measures presented by other issuers.
Fund flows from operations: We define fund flows from operations as cash flows from operating activities before changes in non-cash operating working capital and asset retirement obligations settled. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, fund flows from operations provides a measure of our ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. As we have presented fund flows from operations in the "Segmented Information" note of our unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2015, we consider fund flows from operations to be an additional GAAP financial measure.
Free cash flow: Represents fund flows from operations in excess of capital expenditures. We consider free cash flow to be a key measure as it is used to determine the funding available for investing and financing activities, including payment of dividends, repayment of long-term debt, reallocation to existing business units, and deployment into new ventures.
Net dividends: We define net dividends as dividends declared less proceeds received for the issuance of shares pursuant to the dividend reinvestment plan. Management monitors net dividends and net dividends as a percentage of fund flows from operations to assess our ability to pay dividends.
Payout: We define payout as net dividends plus drilling and development, exploration and evaluation, dispositions and asset retirement obligations settled. Management uses payout to assess the amount of cash distributed back to shareholders and re-invested in the business for maintaining production and organic growth.
Fund flows from operations (excluding Corrib) and Payout (excluding Corrib): Management excludes expenditures relating to the Corrib project in assessing fund flows from operations (an additional GAAP financial measure) and payout in order to assess our ability to generate cash and finance organic growth from our current producing assets.
Net debt: We define net debt as the sum of long-term debt and working capital. Management uses net debt, and the ratio of net debt to fund flows from operations, to analyze our financial position and leverage. Please refer to the preceding "Net Debt" section for a reconciliation of the net debt non-GAAP financial measure.
Diluted shares outstanding: Is the sum of shares outstanding at the period end plus outstanding awards under the VIP, based on current estimates of future performance factors and forfeiture rates.
Cash dividends per share: Represents cash dividends declared per share.
Netbacks: Per boe and per mcf measures used in the analysis of operational activities.
Total returns: Includes cash dividends per share and the change in Vermilion's share price on the Toronto Stock Exchange.
The following tables reconcile fund flows from operations, net dividends, payout, and diluted shares outstanding to their most directly comparable GAAP measures as presented in our financial statements:
Three Months Ended | Six Months Ended | |||||||||||||
Jun 30, | Mar 31, | Jun 30, | Jun 30, | Jun 30, | ||||||||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||
Cash flows from operating activities | 134,668 | 22,647 | 149,592 | 157,315 | 327,830 | |||||||||
Changes in non-cash operating working capital | (6,390) | 95,041 | 64,103 | 88,651 | 88,577 | |||||||||
Asset retirement obligations settled | 1,218 | 3,107 | 2,381 | 4,325 | 5,032 | |||||||||
Fund flows from operations | 129,496 | 120,795 | 216,076 | 250,291 | 421,439 | |||||||||
Expenses related to Corrib | 2,276 | 2,205 | 1,823 | 4,481 | 3,693 | |||||||||
Fund flows from operations (excluding Corrib) | 131,772 | 123,000 | 217,899 | 254,772 | 425,132 | |||||||||
Three Months Ended | Six Months Ended | |||||||||||||
Jun 30, | Mar 31, | Jun 30, | Jun 30, | Jun 30, | ||||||||||
($M) | 2015 | 2015 | 2014 | 2015 | 2014 | |||||||||
Dividends declared | 70,976 | 69,390 | 68,710 | 140,366 | 134,717 | |||||||||
Issuance of shares pursuant to the dividend reinvestment and Premium DividendTM | ||||||||||||||
plans | (42,301) | (21,378) | (19,149) | (63,679) | (38,034) | |||||||||
Net dividends | 28,675 | 48,012 | 49,561 | 76,687 | 96,683 | |||||||||
Drilling and development | 90,173 | 174,311 | 117,975 | 264,484 | 286,815 | |||||||||
Exploration and evaluation | - | - | 17,098 | - | 44,633 | |||||||||
Asset retirement obligations settled | 1,218 | 3,107 | 2,381 | 4,325 | 5,032 | |||||||||
Payout | 120,066 | 225,430 | 187,015 | 345,496 | 433,163 | |||||||||
Corrib drilling and development | (20,267) | (12,955) | (27,221) | (33,222) | (43,457) | |||||||||
Payout (excluding Corrib) | 99,799 | 212,475 | 159,794 | 312,274 | 389,706 | |||||||||
As at | ||||||||||||||
Jun 30, | Mar 31, | Jun 30, | ||||||||||||
('000s of shares) | 2015 | 2015 | 2014 | |||||||||||
Shares outstanding | 109,806 | 107,718 | 106,620 | |||||||||||
Potential shares issuable pursuant to the VIP | 2,820 | 3,043 | 2,751 | |||||||||||
Diluted shares outstanding | 112,626 | 110,761 | 109,371 |
CONSOLIDATED BALANCE SHEETS (THOUSANDS OF CANADIAN DOLLARS, UNAUDITED) |
|||||||
June 30, | December 31, | ||||||
Note | 2015 | 2014 | |||||
ASSETS | |||||||
Current | |||||||
Cash and cash equivalents | 98,038 | 120,405 | |||||
Accounts receivable | 154,843 | 171,820 | |||||
Crude oil inventory | 20,559 | 9,510 | |||||
Derivative instruments | 11,098 | 23,391 | |||||
Prepaid expenses | 17,485 | 13,033 | |||||
302,023 | 338,159 | ||||||
Derivative instruments | - | 1,403 | |||||
Deferred taxes | 163,997 | 154,816 | |||||
Exploration and evaluation assets | 3 | 376,051 | 380,621 | ||||
Capital assets | 2 | 3,586,743 | 3,511,092 | ||||
4,428,814 | 4,386,091 | ||||||
LIABILITIES | |||||||
Current | |||||||
Accounts payable and accrued liabilities | 203,519 | 298,196 | |||||
Current portion of long-term debt | 5 | 224,457 | - | ||||
Dividends payable | 6 | 23,608 | 23,070 | ||||
Derivative instruments | 2,169 | - | |||||
Income taxes payable | 26,095 | 44,463 | |||||
479,848 | 365,729 | ||||||
Long-term debt | 5 | 1,200,077 | 1,238,080 | ||||
Finance lease obligation | 2 | 25,710 | - | ||||
Asset retirement obligations | 4 | 351,291 | 350,753 | ||||
Deferred taxes | 394,806 | 410,183 | |||||
2,451,732 | 2,364,745 | ||||||
SHAREHOLDERS' EQUITY | |||||||
Shareholders' capital | 6 | 2,087,932 | 1,959,021 | ||||
Contributed surplus | 71,443 | 92,188 | |||||
Accumulated other comprehensive (loss) income | (6,869) | 5,722 | |||||
Deficit | (175,424) | (35,585) | |||||
1,977,082 | 2,021,346 | ||||||
4,428,814 | 4,386,091 |
CONSOLIDATED STATEMENTS OF NET EARNINGS AND COMPREHENSIVE INCOME (LOSS)
(THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER SHARE AMOUNTS,
UNAUDITED)
Three Months Ended | Six Months Ended | ||||||||||||
June 30, | June 30, | June 30, | June 30, | ||||||||||
Note | 2015 | 2014 | 2015 | 2014 | |||||||||
REVENUE | |||||||||||||
Petroleum and natural gas sales | 264,331 | 387,684 | 460,216 | 768,867 | |||||||||
Royalties | (16,111) | (29,013) | (32,535) | (53,037) | |||||||||
Petroleum and natural gas revenue | 248,220 | 358,671 | 427,681 | 715,830 | |||||||||
EXPENSES | |||||||||||||
Operating | 58,616 | 58,213 | 102,467 | 116,199 | |||||||||
Transportation | 10,883 | 12,032 | 20,423 | 21,893 | |||||||||
Equity based compensation | 7 | 17,886 | 18,217 | 36,926 | 34,689 | ||||||||
(Gain) loss on derivative instruments | (7,186) | (898) | 6,527 | (7,473) | |||||||||
Interest expense | 14,550 | 12,334 | 27,848 | 23,794 | |||||||||
General and administration | 14,505 | 17,762 | 28,065 | 32,229 | |||||||||
Foreign exchange (gain) loss | (2,291) | 23,159 | (752) | 3,200 | |||||||||
Other expense (income) | - | (178) | (31,736) | (145) | |||||||||
Accretion | 4 | 5,713 | 5,950 | 11,388 | 11,662 | ||||||||
Depletion and depreciation | 2, 3 | 111,146 | 104,902 | 202,103 | 204,354 | ||||||||
223,822 | 251,493 | 403,259 | 440,402 | ||||||||||
EARNINGS BEFORE INCOME TAXES | 24,398 | 107,178 | 24,422 | 275,428 | |||||||||
INCOME TAXES | |||||||||||||
Deferred | (3,130) | 7,851 | (24,358) | 14,471 | |||||||||
Current | 20,715 | 45,334 | 40,692 | 104,176 | |||||||||
17,585 | 53,185 | 16,334 | 118,647 | ||||||||||
NET EARNINGS | 6,813 | 53,993 | 8,088 | 156,781 | |||||||||
OTHER COMPREHENSIVE INCOME (LOSS) | |||||||||||||
Currency translation adjustments | 27,543 | (42,794) | (12,591) | 2,741 | |||||||||
COMPREHENSIVE INCOME (LOSS) | 34,356 | 11,199 | (4,503) | 159,522 | |||||||||
NET EARNINGS PER SHARE | |||||||||||||
Basic | 0.06 | 0.51 | 0.07 | 1.51 | |||||||||
Diluted | 0.06 | 0.50 | 0.07 | 1.49 | |||||||||
WEIGHTED AVERAGE SHARES OUTSTANDING ('000s) | |||||||||||||
Basic | 109,319 | 105,577 | 108,421 | 103,936 | |||||||||
Diluted | 110,746 | 107,330 | 109,792 | 105,531 | |||||||||
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
Three Months Ended | Six Months Ended | |||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||
Note | 2015 | 2014 | 2015 | 2014 | ||||||||||
OPERATING | ||||||||||||||
Net earnings | 6,813 | 53,993 | 8,088 | 156,781 | ||||||||||
Adjustments: | ||||||||||||||
Accretion | 4 | 5,713 | 5,950 | 11,388 | 11,662 | |||||||||
Depletion and depreciation | 2, 3 | 111,146 | 104,902 | 202,103 | 204,354 | |||||||||
Unrealized (gain) loss on derivative instruments | (4,105) | 1,521 | 15,865 | (2,414) | ||||||||||
Equity based compensation | 7 | 17,886 | 18,217 | 36,926 | 34,689 | |||||||||
Unrealized foreign exchange (gain) loss | (5,031) | 23,746 | (186) | 1,746 | ||||||||||
Unrealized other expense (income) | 204 | (104) | 465 | 150 | ||||||||||
Deferred taxes | (3,130) | 7,851 | (24,358) | 14,471 | ||||||||||
Asset retirement obligations settled | 4 | (1,218) | (2,381) | (4,325) | (5,032) | |||||||||
Changes in non-cash operating working capital | 6,390 | (64,103) | (88,651) | (88,577) | ||||||||||
Cash flows from operating activities | 134,668 | 149,592 | 157,315 | 327,830 | ||||||||||
INVESTING | ||||||||||||||
Drilling and development | 2 | (90,173) | (117,975) | (264,484) | (286,815) | |||||||||
Exploration and evaluation | 3 | - | (17,098) | - | (44,633) | |||||||||
Property acquisitions | 2, 3 | (480) | - | (515) | (178,227) | |||||||||
Corporate acquisitions, net of cash acquired | - | (176,179) | - | (176,179) | ||||||||||
Changes in non-cash investing working capital | (39,305) | (24,010) | (27,162) | 15,463 | ||||||||||
Cash flows used in investing activities | (129,958) | (335,262) | (292,161) | (670,391) | ||||||||||
FINANCING | ||||||||||||||
Increase in long-term debt | 32,947 | 255,727 | 187,861 | 205,727 | ||||||||||
Cash dividends | (28,226) | (48,665) | (76,149) | (94,185) | ||||||||||
Cash flows from financing activities | 4,721 | 207,062 | 111,712 | 111,542 | ||||||||||
Foreign exchange gain (loss) on cash held in foreign currencies | 415 | (7,232) | 767 | 6,957 | ||||||||||
Net change in cash and cash equivalents | 9,846 | 14,160 | (22,367) | (224,062) | ||||||||||
Cash and cash equivalents, beginning of period | 88,192 | 151,337 | 120,405 | 389,559 | ||||||||||
Cash and cash equivalents, end of period | 98,038 | 165,497 | 98,038 | 165,497 | ||||||||||
Supplementary information for operating activities - cash payments | ||||||||||||||
Interest paid | 12,510 | 11,721 | 30,755 | 25,815 | ||||||||||
Income taxes paid (refunded) | (11,685) | 56,486 | 58,828 | 77,560 | ||||||||||
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
(THOUSANDS OF CANADIAN DOLLARS, UNAUDITED)
Accumulated | ||||||||||||||||||
Other | Total | |||||||||||||||||
Shareholders' | Contributed | Comprehensive | Shareholders' | |||||||||||||||
Note | Capital | Surplus | Income | Deficit | Equity | |||||||||||||
Balances as at January 1, 2014 | 1,618,443 | 75,427 | 47,142 | (24,637) | 1,716,375 | |||||||||||||
Net earnings | - | - | - | 156,781 | 156,781 | |||||||||||||
Currency translation adjustments | - | - | 2,741 | - | 2,741 | |||||||||||||
Equity based compensation expense | - | 33,968 | - | - | 33,968 | |||||||||||||
Dividends declared | 6 | - | - | - | (134,717) | (134,717) | ||||||||||||
Shares issued pursuant to the dividend reinvestment plan | 6 | 38,034 | - | - | - | 38,034 | ||||||||||||
Shares issued pursuant to corporate acquisition | 204,960 | - | - | - | 204,960 | |||||||||||||
Modification of equity based awards | - | (2,395) | - | - | (2,395) | |||||||||||||
Vesting of equity based awards | 6, 7 | 47,657 | (47,657) | - | - | - | ||||||||||||
Share-settled dividends on vested equity based awards | 6, 7 | 7,519 | - | - | (7,519) | - | ||||||||||||
Shares issued pursuant to the bonus plan | 6 | 721 | - | - | - | 721 | ||||||||||||
Balances as at June 30, 2014 | 1,917,334 | 59,343 | 49,883 | (10,092) | 2,016,468 | |||||||||||||
Accumulated | ||||||||||||||||||
Other | Total | |||||||||||||||||
Shareholders' | Contributed | Comprehensive | Shareholders' | |||||||||||||||
Note | Capital | Surplus | Income (Loss) | Deficit | Equity | |||||||||||||
Balances as at January 1, 2015 | 1,959,021 | 92,188 | 5,722 | (35,585) | 2,021,346 | |||||||||||||
Net earnings | - | - | - | 8,088 | 8,088 | |||||||||||||
Currency translation adjustments | - | - | (12,591) | - | (12,591) | |||||||||||||
Equity based compensation expense | 7 | - | 36,110 | - | - | 36,110 | ||||||||||||
Dividends declared | 6 | - | - | - | (140,366) | (140,366) | ||||||||||||
Shares issued pursuant to the dividend reinvestment and Premium DividendTM plans | 6 | 63,679 | - | - | - | 63,679 | ||||||||||||
Vesting of equity based awards | 6, 7 | 56,855 | (56,855) | - | - | - | ||||||||||||
Share-settled dividends on vested equity based awards | 6, 7 | 7,561 | - | - | (7,561) | - | ||||||||||||
Shares issued pursuant to the employee savings and bonus plans | 6 | 816 | - | - | - | 816 | ||||||||||||
Balances as at June 30, 2015 | 2,087,932 | 71,443 | (6,869) | (175,424) | 1,977,082 |
DESCRIPTION OF EQUITY RESERVES
Shareholders' capital
Represents the recognized amount for common shares when issued, net of
equity issuance costs and deferred taxes.
Contributed surplus
Represents the recognized value of employee awards which are settled in
shares. Once vested, the value of the awards is transferred to
shareholders' capital.
Accumulated other comprehensive (loss) income
Represents the cumulative income and expenses which are not recorded
immediately in net earnings and are accumulated until an event triggers
recognition in net earnings. The current balance consists of currency
translation adjustments resulting from translating financial statements
of subsidiaries with a foreign functional currency to Canadian dollars
at period-end rates.
Deficit
Represents the cumulative net earnings less distributed earnings of
Vermilion Energy Inc.
NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2015 AND 2014
(TABULAR AMOUNTS IN THOUSANDS OF CANADIAN DOLLARS, EXCEPT SHARE AND PER
SHARE AMOUNTS, UNAUDITED)
1. BASIS OF PRESENTATION
Vermilion Energy Inc. (the "Company" or "Vermilion") is a corporation governed by the laws of the Province of Alberta and is actively engaged in the business of crude oil and natural gas exploration, development, acquisition and production.
These condensed consolidated interim financial statements are in compliance with IAS 34, "Interim financial reporting" and have been prepared using the same accounting policies and methods of computation as Vermilion's consolidated financial statements for the year ended December 31, 2014.
These condensed consolidated interim financial statements should be read in conjunction with Vermilion's consolidated financial statements for the year ended December 31, 2014, which are contained within Vermilion's Annual Report for the year ended December 31, 2014 and are available on SEDAR at www.sedar.com or on Vermilion's website at www.vermilionenergy.com.
These condensed consolidated interim financial statements were approved and authorized for issuance by the Board of Directors of Vermilion on August 6, 2015.
2. CAPITAL ASSETS
The following table reconciles the change in Vermilion's capital assets:
Petroleum and | Furniture and | Total | |||||||
($M) | Natural Gas Assets | Office Equipment | Capital Assets | ||||||
Balance at January 1, 2014 | 2,784,634 | 15,211 | 2,799,845 | ||||||
Additions | 608,709 | 9,980 | 618,689 | ||||||
Property acquisitions | 176,625 | - | 176,625 | ||||||
Corporate acquisitions | 390,523 | - | 390,523 | ||||||
Changes in estimate for asset retirement obligations | 19,107 | - | 19,107 | ||||||
Depletion and depreciation | (412,768) | (5,072) | (417,840) | ||||||
Effect of movements in foreign exchange rates | (75,635) | (222) | (75,857) | ||||||
Balance at December 31, 2014 | 3,491,195 | 19,897 | 3,511,092 | ||||||
Additions | 263,466 | 1,018 | 264,484 | ||||||
Property acquisitions | 515 | - | 515 | ||||||
Changes in estimate for asset retirement obligations | (5,773) | - | (5,773) | ||||||
Depletion and depreciation | (201,193) | (2,335) | (203,528) | ||||||
Recognition of finance lease obligation | 31,028 | - | 31,028 | ||||||
Effect of movements in foreign exchange rates | (11,065) | (10) | (11,075) | ||||||
Balance at June 30, 2015 | 3,568,173 | 18,570 | 3,586,743 |
As part of the Elkhorn acquisition in April of 2014, Vermilion assumed an agreement for the construction and use of a solution gas facility which was under construction at the time of acquisition. The substance of the arrangement has been determined to be a lease and has been classified as a finance lease. The carrying amount of the asset and liability at the commencement date in the first quarter of 2015 was $31.0 million, with the liability being apportioned between current ($3.9 million) and long-term ($27.1 million).
3. EXPLORATION AND EVALUATION ASSETS
The following table reconciles the change in Vermilion's exploration and evaluation assets:
($M) | Exploration and Evaluation Assets | |||||
Balance at January 1, 2014 | 136,259 | |||||
Additions | 69,035 | |||||
Changes in estimate for asset retirement obligations | 22 | |||||
Property acquisitions | 46,135 | |||||
Corporate acquisitions | 138,264 | |||||
Depreciation | (5,038) | |||||
Effect of movements in foreign exchange rates | (4,056) | |||||
Balance at December 31, 2014 | 380,621 | |||||
Changes in estimate for asset retirement obligations | (21) | |||||
Depreciation | (4,117) | |||||
Effect of movements in foreign exchange rates | (432) | |||||
Balance at June 30, 2015 | 376,051 | |||||
4. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the change in Vermilion's asset retirement obligations:
($M) | Asset Retirement Obligations | ||||
Balance at January 1, 2014 | 326,162 | ||||
Additional obligations recognized | 22,565 | ||||
Changes in estimates for asset retirement obligations | (3,434) | ||||
Obligations settled | (15,956) | ||||
Accretion | 23,913 | ||||
Changes in discount rates | 9,404 | ||||
Effect of movements in foreign exchange rates | (11,901) | ||||
Balance at December 31, 2014 | 350,753 | ||||
Additional obligations recognized | 3,395 | ||||
Obligations settled | (4,325) | ||||
Accretion | 11,388 | ||||
Changes in discount rates | (9,189) | ||||
Effect of movements in foreign exchange rates | (731) | ||||
Balance at June 30, 2015 | 351,291 | ||||
5. LONG-TERM DEBT
The following table summarizes Vermilion's outstanding long-term debt:
As at | ||||||||
($M) | June 30, 2015 | Dec 31, 2014 | ||||||
Revolving credit facility | 1,200,077 | 1,014,067 | ||||||
Senior unsecured notes (1) | 224,457 | 224,013 | ||||||
Long-term debt | 1,424,534 | 1,238,080 |
(1) |
The senior unsecured notes, which will mature on February 10, 2016, are included in the current portion of long-term debt as at June 30, 2015. |
Revolving Credit Facility
At June 30, 2015, Vermilion had in place a bank revolving credit facility totalling $2 billion, of which approximately $1.20 billion was drawn. The facility, which matures on May 31, 2019, is fully revolving up to the date of maturity.
The facility is extendable from time to time, but not more than once per year, for a period not longer than four years, at the option of the lenders and upon notice from Vermilion. If no extension is granted by the lenders, the amounts owing pursuant to the facility are due at the maturity date. This facility bears interest at a rate applicable to demand loans plus applicable margins. For the six months ended June 30, 2015, the interest rate on the revolving credit facility was approximately 3.0% (2014 - 3.1%).
The amount available to Vermilion under this facility is reduced by certain outstanding letters of credit associated with Vermilion's operations totalling $26.5 million as at June 30, 2015 (December 31, 2014 - $8.6 million).
The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. Under the terms of the facility, Vermilion must maintain:
As at June 30, 2015, Vermilion was in compliance with all financial covenants.
Senior Unsecured Notes
On February 10, 2011, Vermilion issued $225.0 million of senior unsecured notes at par. The notes bear interest at a rate of 6.5% per annum and will mature on February 10, 2016. As direct senior unsecured obligations of Vermilion, the notes rank pari passu with all other present and future unsecured and unsubordinated indebtedness of the Company. Vermilion may redeem all or part of the senior unsecured notes at 100% of their principal amount plus any accrued and unpaid interest. The notes were initially recognized at fair value net of transaction costs and are subsequently measured at amortized cost using an effective interest rate of 7.1%.
6. SHAREHOLDERS' CAPITAL
The following table reconciles the change in Vermilion's shareholders' capital:
Shareholders' Capital | Number of Shares ('000s) | Amount ($M) | ||||||
Balance as at January 1, 2014 | 102,123 | 1,618,443 | ||||||
Shares issued pursuant to corporate acquisition | 2,827 | 204,960 | ||||||
Shares issued pursuant to the dividend reinvestment plan | 1,279 | 79,430 | ||||||
Vesting of equity based awards | 955 | 47,925 | ||||||
Share-settled dividends on vested equity based awards | 108 | 7,542 | ||||||
Shares issued pursuant to the bonus plan | 11 | 721 | ||||||
Balance as at December 31, 2014 | 107,303 | 1,959,021 | ||||||
Shares issued pursuant to the dividend reinvestment and Premium DividendTM plans | 1,195 | 63,679 | ||||||
Vesting of equity based awards | 1,158 | 56,855 | ||||||
Share-settled dividends on vested equity based awards | 135 | 7,561 | ||||||
Shares issued pursuant to the employee savings and bonus plans | 15 | 816 | ||||||
Balance as at June 30, 2015 | 109,806 | 2,087,932 |
Dividends declared to shareholders for the six months ended June 30, 2015 were $140.4 million (2014 - $134.7 million).
Subsequent to the end of the period and prior to the condensed consolidated interim financial statements being authorized for issue on August 6, 2015, Vermilion declared dividends totalling $23.7 million or $0.215 per share.
7. EQUITY BASED COMPENSATION
The following table summarizes the number of awards outstanding under the Vermilion Incentive Plan ("VIP"):
Six Months | Full Year | |||||||
Number of Awards ('000s) | 2015 | 2014 | ||||||
Opening balance | 1,775 | 1,665 | ||||||
Granted | 585 | 707 | ||||||
Vested | (587) | (515) | ||||||
Modified | - | (21) | ||||||
Forfeited | (44) | (61) | ||||||
Closing balance | 1,729 | 1,775 |
The fair value of a VIP award is determined on the grant date at the closing price of Vermilion's common shares on the Toronto Stock Exchange, adjusted by the estimated performance factor that will ultimately be achieved.
8. SEGMENTED INFORMATION
Vermilion has operations in three core areas: North America, Europe, and Australia. Vermilion's operating activities in each country relate solely to the exploration, development and production of petroleum and natural gas. Vermilion has a Corporate head office located in Calgary, Alberta. Costs incurred in the Corporate segment relate to Vermilion's global hedging program and expenses incurred in financing and managing our operating business units.
Vermilion's chief operating decision maker reviews the financial performance of the Company by assessing the fund flows from operations of each country individually. Fund flows from operations provides a measure of each business unit's ability to generate cash (that is not subject to short-term movements in non-cash operating working capital) necessary to pay dividends, fund asset retirement obligations, and make capital investments.
Three Months Ended June 30, 2015 | ||||||||||||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia |
United States |
Corporate | Total | |||||||||||||||||
Drilling and development | 21,881 | 16,697 | 18,885 | 3,231 | 20,267 | 6,468 | 2,744 | - | 90,173 | |||||||||||||||||
Oil and gas sales to external customers | 91,284 | 81,627 | 23,913 | 10,626 | - | 56,204 | 677 | - | 264,331 | |||||||||||||||||
Royalties | (5,768) | (6,620) | (1,294) | (2,238) | - | - | (191) | - | (16,111) | |||||||||||||||||
Revenue from external customers | 85,516 | 75,007 | 22,619 | 8,388 | - | 56,204 | 486 | - | 248,220 | |||||||||||||||||
Transportation expense | (4,469) | (3,526) | - | (1,240) | (1,648) | - | - | - | (10,883) | |||||||||||||||||
Operating expense | (21,534) | (12,102) | (5,414) | (1,373) | - | (18,083) | (110) | - | (58,616) | |||||||||||||||||
General and administration | (5,510) | (4,874) | (454) | (1,435) | (628) | (1,141) | (963) | 500 | (14,505) | |||||||||||||||||
PRRT | - | - | - | - | - | (3,371) | - | - | (3,371) | |||||||||||||||||
Corporate income taxes | - | (9,316) | (2,347) | - | - | (5,134) | - | (547) | (17,344) | |||||||||||||||||
Interest expense | - | - | - | - | - | - | - | (14,550) | (14,550) | |||||||||||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 3,081 | 3,081 | |||||||||||||||||
Realized foreign exchange loss | - | - | - | - | - | - | - | (2,740) | (2,740) | |||||||||||||||||
Realized other income | - | - | - | - | - | - | - | 204 | 204 | |||||||||||||||||
Fund flows from operations | 54,003 | 45,189 | 14,404 | 4,340 | (2,276) | 28,475 | (587) | (14,052) | 129,496 | |||||||||||||||||
Three Months Ended June 30, 2014 | ||||||||||||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia |
United States |
Corporate | Total | |||||||||||||||||
Drilling and development | 26,071 | 34,828 | 18,234 | 630 | 27,221 | 10,991 | - | - | 117,975 | |||||||||||||||||
Exploration and evaluation | 10,897 | 2,786 | 3,279 | - | - | - | - | 136 | 17,098 | |||||||||||||||||
Oil and gas sales to external customers | 163,261 | 124,617 | 29,881 | 11,097 | - | 58,828 | - | - | 387,684 | |||||||||||||||||
Royalties | (18,240) | (7,796) | (693) | (2,284) | - | - | - | - | (29,013) | |||||||||||||||||
Revenue from external customers | 145,021 | 116,821 | 29,188 | 8,813 | - | 58,828 | - | - | 358,671 | |||||||||||||||||
Transportation expense | (4,024) | (5,385) | - | (1,052) | (1,571) | - | - | - | (12,032) | |||||||||||||||||
Operating expense | (21,179) | (16,550) | (6,390) | (2,043) | - | (12,051) | - | - | (58,213) | |||||||||||||||||
General and administration | (6,560) | (5,559) | (326) | (830) | (252) | (1,661) | - | (2,574) | (17,762) | |||||||||||||||||
PRRT | - | - | - | - | - | (12,699) | - | - | (12,699) | |||||||||||||||||
Corporate income taxes | - | (24,761) | (1,301) | (506) | - | (5,689) | - | (378) | (32,635) | |||||||||||||||||
Interest expense | - | - | - | - | - | - | - | (12,334) | (12,334) | |||||||||||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 2,419 | 2,419 | |||||||||||||||||
Realized foreign exchange gain | - | - | - | - | - | - | - | 587 | 587 | |||||||||||||||||
Realized other income | - | - | - | - | - | - | - | 74 | 74 | |||||||||||||||||
Fund flows from operations | 113,258 | 64,566 | 21,171 | 4,382 | (1,823) | 26,728 | - | (12,206) | 216,076 | |||||||||||||||||
Six Months Ended June 30, 2015 | ||||||||||||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia |
United States |
Corporate | Total | |||||||||||||||||
Total assets | 1,931,640 | 854,608 | 211,587 | 163,069 | 856,739 | 233,956 | 18,785 | 158,430 | 4,428,814 | |||||||||||||||||
Drilling and development | 136,730 | 50,811 | 23,218 | 4,199 | 33,222 | 12,923 | 3,381 | - | 264,484 | |||||||||||||||||
Oil and gas sales to external customers | 169,168 | 141,459 | 50,731 | 22,021 | - | 75,488 | 1,349 | - | 460,216 | |||||||||||||||||
Royalties | (14,360) | (11,722) | (2,220) | (3,836) | - | - | (397) | - | (32,535) | |||||||||||||||||
Revenue from external customers | 154,808 | 129,737 | 48,511 | 18,185 | - | 75,488 | 952 | - | 427,681 | |||||||||||||||||
Transportation expense | (8,411) | (6,537) | - | (2,134) | (3,341) | - | - | - | (20,423) | |||||||||||||||||
Operating expense | (40,633) | (22,928) | (11,240) | (3,372) | - | (23,969) | (325) | - | (102,467) | |||||||||||||||||
General and administration | (9,525) | (9,985) | (1,191) | (3,043) | (1,140) | (2,595) | (2,043) | 1,457 | (28,065) | |||||||||||||||||
PRRT | - | - | - | - | - | (5,725) | - | - | (5,725) | |||||||||||||||||
Corporate income taxes | - | (23,597) | (4,735) | - | - | (5,711) | - | (924) | (34,967) | |||||||||||||||||
Interest expense | - | - | - | - | - | - | - | (27,848) | (27,848) | |||||||||||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 9,338 | 9,338 | |||||||||||||||||
Realized foreign exchange gain | - | - | - | - | - | - | - | 566 | 566 | |||||||||||||||||
Realized other income | - | 31,775 | - | - | - | - | - | 426 | 32,201 | |||||||||||||||||
Fund flows from operations | 96,239 | 98,465 | 31,345 | 9,636 | (4,481) | 37,488 | (1,416) | (16,985) | 250,291 | |||||||||||||||||
Six Months Ended June 30, 2014 | ||||||||||||||||||||||||||
($M) | Canada | France | Netherlands | Germany | Ireland | Australia |
United States |
Corporate | Total | |||||||||||||||||
Total assets | 1,854,501 | 916,712 | 235,723 | 174,735 | 799,394 | 277,624 | - | 125,726 | 4,384,415 | |||||||||||||||||
Drilling and development | 127,744 | 64,681 | 33,425 | 826 | 43,457 | 16,682 | - | - | 286,815 | |||||||||||||||||
Exploration and evaluation | 24,163 | 10,900 | 8,206 | - | - | - | - | 1,364 | 44,633 | |||||||||||||||||
Oil and gas sales to external customers | 286,441 | 242,177 | 71,435 | 20,012 | - | 148,802 | - | - | 768,867 | |||||||||||||||||
Royalties | (30,903) | (15,147) | (2,901) | (4,086) | - | - | - | - | (53,037) | |||||||||||||||||
Revenue from external customers | 255,538 | 227,030 | 68,534 | 15,926 | - | 148,802 | - | - | 715,830 | |||||||||||||||||
Transportation expense | (7,122) | (10,138) | - | (1,474) | (3,159) | - | - | - | (21,893) | |||||||||||||||||
Operating expense | (37,789) | (32,970) | (12,432) | (3,597) | - | (29,411) | - | - | (116,199) | |||||||||||||||||
General and administration | (9,428) | (10,753) | (924) | (1,398) | (534) | (2,867) | - | (6,325) | (32,229) | |||||||||||||||||
PRRT | - | - | - | - | - | (32,938) | - | - | (32,938) | |||||||||||||||||
Corporate income taxes | - | (50,025) | (5,089) | (1,043) | - | (14,530) | - | (551) | (71,238) | |||||||||||||||||
Interest expense | - | - | - | - | - | - | - | (23,794) | (23,794) | |||||||||||||||||
Realized gain on derivative instruments | - | - | - | - | - | - | - | 5,059 | 5,059 | |||||||||||||||||
Realized foreign exchange loss | - | - | - | - | - | - | - | (1,454) | (1,454) | |||||||||||||||||
Realized other income | - | - | - | - | - | - | - | 295 | 295 | |||||||||||||||||
Fund flows from operations | 201,199 | 123,144 | 50,089 | 8,414 | (3,693) | 69,056 | - | (26,770) | 421,439 | |||||||||||||||||
Reconciliation of fund flows from operations to net earnings
Three Months Ended | Six Months Ended | ||||||||||||
June 30, | June 30, | June 30, | June 30, | ||||||||||
($M) | 2015 | 2014 | 2015 | 2014 | |||||||||
Fund flows from operations | 129,496 | 216,076 | 250,291 | 421,439 | |||||||||
Equity based compensation | (17,886) | (18,217) | (36,926) | (34,689) | |||||||||
Unrealized gain (loss) on derivative instruments | 4,105 | (1,521) | (15,865) | 2,414 | |||||||||
Unrealized foreign exchange gain (loss) | 5,031 | (23,746) | 186 | (1,746) | |||||||||
Unrealized other (expense) income | (204) | 104 | (465) | (150) | |||||||||
Accretion | (5,713) | (5,950) | (11,388) | (11,662) | |||||||||
Depletion and depreciation | (111,146) | (104,902) | (202,103) | (204,354) | |||||||||
Deferred taxes | 3,130 | (7,851) | 24,358 | (14,471) | |||||||||
Net earnings | 6,813 | 53,993 | 8,088 | 156,781 | |||||||||
9. CAPITAL DISCLOSURES
Three Months Ended | Six Months Ended | |||||||||||
($M except as indicated) | June 30, 2015 | June 30, 2014 | June 30, 2015 | June 30, 2014 | ||||||||
Long-term debt | 1,200,077 | 1,198,866 | 1,200,077 | 1,198,866 | ||||||||
Current liabilities(1) | 479,848 | 377,710 | 479,848 | 377,710 | ||||||||
Current assets | (302,023) | (407,578) | (302,023) | (407,578) | ||||||||
Net debt [1] | 1,377,902 | 1,168,998 | 1,377,902 | 1,168,998 | ||||||||
Cash flows from operating activities | 134,668 | 149,592 | 157,315 | 327,830 | ||||||||
Changes in non-cash operating working capital | (6,390) | 64,103 | 88,651 | 88,577 | ||||||||
Asset retirement obligations settled | 1,218 | 2,381 | 4,325 | 5,032 | ||||||||
Fund flows from operations | 129,496 | 216,076 | 250,291 | 421,439 | ||||||||
Annualized fund flows from operations [2] | 517,984 | 864,304 | 500,582 | 842,878 | ||||||||
Ratio of net debt to annualized fund flows from operations ([1] ÷ [2]) | 2.7 | 1.4 | 2.8 | 1.4 |
(1) |
Includes the current portion of long-term debt, which, as at June 30,
2015, represents the senior unsecured notes that will mature on February 10, 2016. |
Long-term debt, including the current portion, as at June 30, 2015 increased to $1.42 billion from $1.24 billion as at December 31, 2014, primarily as a result of draws on the revolving credit facility to fund capital expenditures as fund flows from operations for the six months ended June 30, 2015 were lower due to weakening crude oil and North American natural gas prices. The increase in long-term debt resulted in an increase in net debt from $1.27 billion to $1.38 billion.
Due to this increase in net debt as well as the lower commodity price environment, lower sales volumes, and the aforementioned capital expenditures, the ratio of net debt to fund flows from operations increased to 2.8 for the six months ended June 30, 2015.
10. FINANCIAL INSTRUMENTS
Classification of Financial Instruments
The following table summarizes information relating to Vermilion's financial instruments as at June 30, 2015 and December 31, 2014:
As at Jun 30, 2015 | As at Dec 31, 2014 | ||||||||||||||||
Class of financial instrument |
Consolidated balance sheet caption |
Accounting designation |
Related caption on Statement of Net Earnings |
Carrying value ($M) |
Fair value ($M) |
Carrying value ($M) |
Fair value ($M) |
Fair value measurement hierarchy |
|||||||||
Cash |
Cash and cash equivalents |
HFT |
Gains and losses on foreign exchange are included in foreign exchange (gain) loss |
98,038 | 98,038 | 120,405 | 120,405 | Level 1 | |||||||||
Receivables | Accounts receivable | LAR |
Gains and losses on foreign exchange are included in foreign exchange (gain) loss and impairments are recognized as general and administration expense |
154,843 | 154,843 | 171,820 | 171,820 | Not applicable | |||||||||
Derivative assets | Derivative instruments | HFT | (Gain) loss on derivative instruments | 11,098 | 11,098 | 24,794 | 24,794 | Level 2 | |||||||||
Derivative liabilities | Derivative instruments | HFT | (Gain) loss on derivative instruments | (2,169) | (2,169) | - | - | Level 2 | |||||||||
Payables |
Accounts payable and accrued liabilities |
OTH |
Gains and losses on foreign exchange are included in foreign exchange (gain) loss |
(227,127) | (227,127) | (321,266) | (321,266) | Not applicable | |||||||||
Dividends payable | |||||||||||||||||
Long-term debt | Long-term debt | OTH | Interest expense | (1,424,534) | (1,425,921) | (1,238,080) | (1,238,505) | Level 2 |
The accounting designations used in the above table refer to the following:
HFT - Classified as "Held for trading" in accordance with International Accounting Standard 39 "Financial Instruments: Recognition and Measurement". These financial assets and liabilities are carried at fair value on the consolidated balance sheets with associated gains and losses reflected in net earnings.
LAR - "Loans and receivables" are initially recognized at fair value and are subsequently measured at amortized cost. Impairments and foreign exchange gains and losses are recognized in net earnings.
OTH - "Other financial liabilities" are initially recognized at fair value net of transaction costs directly attributable to the issuance of the instrument and subsequently are measured at amortized cost. Interest is recognized in net earnings using the effective interest method. Foreign exchange gains and losses are recognized in net earnings.
Level 1 - Fair value measurement is determined by reference to unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2 - Fair value measurement is determined based on inputs other than unadjusted quoted prices that are observable, either directly or indirectly.
Level 3 - Fair value measurement is based on inputs for the asset or liability that are not based on observable market data.
Determination of Fair Values
The level in the fair value hierarchy into which the fair value measurements are categorized is determined on the basis of the lowest level input that is significant to the fair value measurement. Transfers between levels on the fair value hierarchy are deemed to have occurred at the end of the reporting period.
Fair values for derivative assets and derivative liabilities are determined using pricing models incorporating future prices that are based on assumptions which are supported by prices from observable market transactions and are adjusted for credit risk.
The carrying value of receivables approximate their fair value due to their short maturities.
The carrying value of long-term debt outstanding on the revolving credit facility approximates its fair value due to the use of short-term borrowing instruments at market rates of interest.
The fair value of the senior unsecured notes changes in response to changes in the market rates of interest payable on similar instruments and was determined with reference to prevailing market rates for such instruments.
Nature and Extent of Risks Arising from Financial Instruments
Market risk:
Vermilion's financial instruments are exposed to currency risk related
to changes in foreign currency denominated financial instruments and
commodity price risk related to outstanding derivative positions. The
following table summarizes what the impact on comprehensive income
before tax would be for the six months ended June 30, 2015 given
changes in the relevant risk variables that Vermilion considers were
reasonably possible at the balance sheet date. The impact on
comprehensive income before tax associated with changes in these risk
variables for assets and liabilities that are not considered financial
instruments are excluded from this analysis. This analysis does not
attempt to reflect any interdependencies between the relevant risk
variables.
Before tax effect on comprehensive | ||||||
income - increase (decrease) | ||||||
Risk ($M) | Description of change in risk variable | June 30, 2015 | ||||
Currency risk - Euro to Canadian |
Increase in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates |
(2,390) | ||||
Decrease in strength of the Canadian dollar against the Euro by 5% over the relevant closing rates |
2,390 | |||||
Currency risk - US $ to Canadian |
Increase in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates |
(5,147) | ||||
Decrease in strength of the Canadian dollar against the US $ by 5% over the relevant closing rates |
5,147 | |||||
Commodity price risk |
Increase in relevant oil reference price within option pricing models used to determine the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates |
(1,742) | ||||
Decrease in relevant oil reference price within option pricing models used to determine the fair value of financial derivatives by US $5.00/bbl at the relevant valuation dates |
1,888 | |||||
Increase in relevant TTF reference price within option pricing models used to determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates |
(8,404) | |||||
Decrease in relevant TTF reference price within option pricing models used to determine the fair value of financial derivatives by € 0.5/GJ at the relevant valuation dates |
8,399 | |||||
Interest rate risk |
Increase in average Canadian prime interest rate by 100 basis points during the relevant periods |
(5,506) | ||||
Decrease in average Canadian prime interest rate by 100 basis points during the relevant periods |
5,506 |
11. SIGNIFICANT TRANSACTIONS
During Q1 2015, Vermilion was awarded a recovery of costs resulting from an oil spill at the Ambès oil terminal in France that occurred in 2007. The French court awarded Vermilion approximately €25 million (before taxes), of which 50% was due immediately to Vermilion upon posting a surety bond. The payment was received in Q2 2015, with the remainder due upon conclusion of the appeal process. Based on the recent court decision and the conclusions of the expert engaged by the French court, Vermilion is virtually certain that the award will be upheld.
SOURCE Vermilion Energy Inc.
Copyright 2015 PR Newswire
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