CALGARY, ALBERTA — (Marketwire) — 07/14/11 — Nexen Inc. today reported second quarter 2011 operating and financial results, led by strong oil prices, high netbacks, and a portfolio weighted towards unhedged, Brent-priced oil. We generated cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share). Production of 204,000 barrels of oil equivalent per day (boe/d) reflects maintenance activities at our Buzzard platform in the UK North Sea which are expected to be completed in August. In light of our production in the first half of the year, we now expect company-wide production before royalties for the year to average between 210,000 and 230,000 boe/d.
During the quarter, we achieved several milestones. Our Usan project remains on track, with the floating production and storage offloading vessel (FPSO) enroute to site. The project is expected to achieve first oil in the first half of 2012. In our oil sands business, Long Lake production increased 9% over the first quarter and generated positive cash flow for the quarter. In June, we processed 45,000 barrels per day (bbls/d) of proprietary and third- party bitumen volumes (28,900 bbls/d and 16,100 bbls/day respectively) achieving approximately 65% of upgrader capacity. We continued to advance various initiatives for resource development to fill the upgrader. We also continued our industry-leading execution in our shale gas business with the drilling of a nine-well pad. We began fracing and completion activities during the quarter, and first production from this pad is expected in the fourth quarter. We also commenced drilling an 18-well pad.
Our exploration efforts advanced in the Gulf of Mexico. We received a drilling permit for our Kakuna exploration well and commenced drilling late in June. Our partner, Shell, received a drilling permit for an appraisal well to follow up our Appomattox discovery.
“While we are disappointed with the downtime at Buzzard, we are making steady progress in all areas of our business. We continue to focus on developing our attractive opportunity portfolio and are advancing our near-term and longer-term value contributors to our business,” said Marvin Romanow, President and Chief Executive Officer.
“The Gulf of Mexico is a key component of our significant resource potential, and we are excited to be back to drilling,” continued Mr. Romanow. “We–ve spent the past several years building an attractive prospect inventory in the Gulf, and the value of the opportunity in this area was highlighted by the Appomattox discovery last year. Along with the North Sea and West Africa, the Gulf is expected to be integral to growing our conventional business for many years to come.”
Highlights
Financial
– Cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share).
– Oil and gas operations generated a cash netback of $59.87/boe ($42.76/boe after tax).
– Achieved our first quarterly positive cash flow at Long Lake.
– Net debt decreased approximately 50% from a year ago. It is expected to increase in the second half of the year as our capital program is weighted more towards the latter half of the year as we increase our drilling activities.
Production
– Production of 204,000 boe/d (180,000 boe/d after royalties) was impacted by Buzzard–s unscheduled maintenance and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. We also had unscheduled downtime at Syncrude.
– At Long Lake, production increased 9% over the prior quarter to 27,900 bbls/d gross (18,100 bbls/d net to Nexen).
Project Advancements
– Received drilling permits for the Appomattox appraisal well and Kakuna exploration well in the deepwater Gulf of Mexico. Commenced drilling the Kakuna well and brought in Statoil USA E&P Inc. as a partner on a promoted basis.
– Continued industry-leading pace of drilling at our shale gas operations in the Horn River. We have strong interest in our joint venture process.
– Advancing various projects to develop high quality resource to fill the Long Lake upgrader, including acceleration of development of a portion of the Kinosis lease.
– Successfully ran the Long Lake upgrader at approximately 65% of capacity, with an on-stream factor of 96% during June.
– Continued drilling on pads 12 and 13 at Long Lake, and converted several pad 11 wells from circulation to production.
– Usan FPSO set sail for location offshore Nigeria, West Africa.
Our portfolio weighting towards unhedged, Brent-priced oil contributed to strong cash flow in the quarter. Brent averaged US$117.36 per barrel, a premium of US$14.80 per barrel over WTI. Our approach to hedging allows us to benefit when prices rise, while giving us some protection if prices decline below certain levels. Higher realized crude oil prices, which averaged $110.28 per barrel, partially offset lower production from temporary downtime at Buzzard and Syncrude and natural declines in Yemen. Also contributing to cash flow was our Long Lake operation, which generated its first positive quarterly cash flow of $6 million as compared to a loss of $19 million in the first quarter. Higher production, prices and upgrader throughput contributed to this positive cash flow.
Net income increased from the prior quarter. The first quarter included the impact of the UK tax rate change which resulted in an accrual for higher income taxes of $336 million. This was partially offset by a $299 million after-tax gain on the sale of Canexus.
Net debt has declined about 50% over the past year following our successful asset disposition program and a stronger Canadian dollar. This amount is expected to rise in the second half of the year due to the timing of our capital spending and working capital changes. Capital investment is expected to increase in the latter half of the year with the increased drilling in the Gulf of Mexico, the North Sea and for Canadian shale gas and oil sands.
The Buzzard field continues to be our largest producing asset and typically contributes 85,000 to 95,000 boe/d net to Nexen. Production in the quarter averaged 114,000 boe/d (49,000 boe/d net to Nexen). This reflects unscheduled maintenance to repair the cooling system and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. While the repair work proceeded on schedule, production was lower than expected due to the gas export restrictions. Production is expected to be back to full rates in August.
We utilized Buzzard–s downtime to bring forward maintenance work originally scheduled for September. Further maintenance work will be advanced to August when the third-party operated Forties pipeline system undergoes a one-week shutdown. As a result, the September shutdown will not be required.
Yemen production reflects natural field declines following the completion of development drilling activities as we near the end of the primary contract term in December of this year, and by the two-day shutdown during a labour strike. This was the longest disruption in our Yemen operations since production began in 1993. Following a successful restart, the facility quickly returned to normal production. We remain confident that we can continue to manage our operations during the current period of uncertainty in the country. Safety and security continue to be our primary focus.
Unscheduled maintenance on the LC Finer and the Vacuum Distillation Unit impacted Syncrude production. The repairs have been completed and production subsequently returned to full rates.
At Long Lake, bitumen production averaged 27,900 bbls/d gross (18,100 bbls/d net to Nexen), up 2,300 bbls/d from the first quarter. Production is increasing as a result of higher steam injection following the hot lime softener (HLS) scheduled maintenance, well optimizations and the continuing ramp-up of the new pad 11 wells. Production at the end of June was approximately 30,000 bbls/d and we expect production from Long Lake to continue to increase into the mid-30,000 bbls/d range by year-end.
Unit operating costs temporarily increased in the first half of this year due to planned and unplanned maintenance, along with initiatives to increase upgrader reliability and improve well performance. The first quarter included planned maintenance of the first HLS unit. The second quarter included planned maintenance on the second HLS unit and a cogeneration unit, as well as unplanned maintenance on the sulphur recovery units and gasifiers. The third HLS unit and second cogeneration unit are scheduled to undergo maintenance in August. Despite this increase in operating costs, the facility generated positive cash flow for the quarter due to higher production and prices, and increased upgrader throughput from Long Lake and third-party sourced bitumen.
Guidance Update
We generate a large portion of our production volumes from a relatively small number of high-netback fields. While our focus on developing high-netback legacy assets provides us with a competitive advantage in our operating areas and delivers attractive value, it results in our production being sensitive to operating rates in these areas.
Given the impact of operational events at Buzzard and Long Lake in the first half of the year, our annual production before royalties is now expected to be 210,000 to 230,000 boe/d. This is lower than we expected in May largely as a result of the gas export restrictions. The range reflects variability of production at Buzzard as we complete the cooling system repairs and the final stages of commissioning the fourth platform that will allow us to produce from our full suite of wells regardless of H2S levels. It also reflects variability in the Long Lake ramp-up, timing of Telford and Blackbird well tie-ins, and potential for hurricane disruptions in the Gulf of Mexico. The following provides production ranges by quarter and major areas:
The production guidance for the various areas reflect:
– In the UK:
— Buzzard repairs of the cooling system and completion of the start-up of the fourth platform continues into the third quarter. The facility will also be taken down in early August for the planned one-week shutdown of the third-party operated Forties pipeline. Once the fourth platform is available, production is expected to be strong as we will be able to almost double the number of available wells as we bring our higher concentration sour producers onstream.
— Planned maintenance activities at Scott and Ettrick in the third quarter.
— Production is expected to increase late in the year with the start-up of production from the tie-ins of the Telford TAC well to the Scott facility, and the Blackbird field to the Ettrick facility.
– In Yemen, production will continue with natural field declines. Our current contract expires in mid-December unless we receive a contract extension.
– In the U.S., the range of production is based on the potential for hurricane-related disruptions through the third quarter and into the early part of the fourth quarter.
– At Long Lake, the ongoing ramp-up of pad 11 and well optimizations are expected to contribute to modest production growth over the remainder of the year.
We expect to add new production next year with Usan coming on-stream in the first half of the year and the start-up of our 18-well shale gas pad and Long Lake pad 12 in the fourth quarter of the year.
Project Advancements
Nexen has numerous opportunities available with several development and appraisal projects underway, and a large resource base to support growth. Near-term projects include new production from a Telford development well; the Blackbird field tie-in; ongoing shale gas drilling; and the Rochelle development. Longer-term projects include Golden Eagle, Appomattox, Knotty Head and Owowo, along with further oil sands and shale gas development.
During the second quarter, we made significant progress on our key milestones in moving these projects into production and cash flow.
Conventional
Offshore West Africa – Development of the Usan field remains on track for first oil in the first half of 2012. Fabrication of the FPSO vessel in Korea is now complete. The FPSO is under tow and expected to arrive on location offshore Nigeria this summer for hook-up to the wells and commissioning. At full capacity, the project is capable of producing 180,000 boe/d (36,000 boe/d net to Nexen). Nexen has a 20% interest in Usan and the project joint venture partners are Total E&P Nigeria Limited (the operator), ExxonMobil and Chevron.
Gulf of Mexico – Shell, the operator of the Appomattox discovery, received approval of the supplemental Exploration Plan for a multi-well exploration and appraisal drilling program on the Appomattox discovery. They received a drilling permit for the first appraisal well and expect to spud it in the third quarter. This is the first of three wells planned to appraise Appomattox and adjacent structures. Nexen estimates the recoverable contingent resource for this discovery exceeds 250 million boe (gross) with further upside potential. Nexen has a 20% working interest in Appomattox and a 25% working interest in the nearby Vicksburg discovery.
Nexen received approval to drill the Kakuna exploration well which spud in late June in the vicinity of the producing Tahiti field and various other discoveries. Following the Kakuna well, we expect to drill the Angel Fire prospect once the drilling permit is approved. Farm-out negotiations continue on exploration prospects in the Gulf of Mexico.
UK North Sea – The approval process for the Golden Eagle development continues to progress well. Development of the field is expected to commence once all partners complete their approval processes and regulatory approvals are in place, which we expect to occur later this summer.
Regulatory approval was received for the Blackbird tieback to the Ettrick facility. We also continue to progress the tie-in of the Telford TAC well to the Scott platform. Blackbird and Telford are both on track to deliver increased production late this year. These projects, when combined with the Rochelle tie-back to the Scott platform, are expected to contribute approximately 10,000 to 20,000 boe/d net to Nexen by the end of 2012. Over the next 12 months, the company plans to drill an appraisal of the Polecat discovery and a number of exploration prospects, including the North Uist well west of the Shetland Islands.
Oil Sands
Long Lake – Our primary focus is on increasing our bitumen production to fill the upgrader. This provides us with an attractive return on capital as the predominantly fixed cost nature of the operation means that each incremental barrel of production contributes significantly to cash flow and profitability. With the upgrader operating at an average of about 50% capacity during the quarter, we generated positive cash flow. At full capacity and US$90 WTI, the project is expected to generate about $800 million of cash flow annually.
Our strategy for filling the upgrader includes:
– growth in production from the initial 10 pads;
– ramp-up of pad 11;
– start-up of pads 12 and 13 that are currently being drilled;
– drilling of pads 14 and 15 which we are targeting to commence drilling in 2012;
– identifying future drilling on the Long Lake and Kinosis leases; and
– processing of third-party sourced bitumen in the interim to enhance returns from this facility.
We believe the continued drilling of high-quality resource on Long Lake and the advancement of Kinosis drilling is the most economic and expedient strategy to grow and sustain our proprietary bitumen volumes to fill the upgrader.
Initially, we expected to fill the upgrader from the first 11 pads that are now on-stream; however, we underestimated the impact lean zones and shales would have on production rates and steam-oil ratio (SOR). We better understand the correlation between reservoir characteristics and production and SOR, based on the range of well performance we experienced in the initial wells. This understanding allows us to target the best quality resource for development that is analogous to the wells in our initial set that are exhibiting good performance. It also confirms that our oil sands lands, including undeveloped areas on the Long Lake lease, contain attractive resource.
We expect production from pads 1 to 11 to continue to increase over time from additional steam, heating through the lean zones, the ramp-up of wells as they mature, and well work-over activities. Production from pad 11 is currently approximately 1,700 bbls/d and is expected to contribute 4,000 to 8,000 bbls/d at maturity.
Pads 12 and 13 were the first to be targeted at the higher quality resource from across the entire lease rather than concentrating on the resource in the vicinity of the upgrader. Well logs and core data indicate these 18 wells are similar to our best producing wells on the lease, which are meeting or exceeding expectations. They also compare favorably with wells drilled on leases by other companies that match our performance expectations. Drilling on the two pads is in progress. Pad 12 is expected to start steaming in the second quarter of next year and pad 13 in the third quarter. Production is expected about three months after first steam and is expected to ramp-up to full rates over the following 12 to 18 months. We expect production from these two pads to contribute 11,000 to 17,000 bbls/d at maturity.
We plan to commence drilling 10 to 12 wells on pads 14 and 15 in 2012, subject to regulatory approvals. First steam to these wells is expected in late 2013. These wells are also targeting high quality resource. We expect production from these two pads to contribute 6,000 to 9,000 bbls/d at maturity.
We are also progressing the acceleration of the development of 25 to 30 wells at Kinosis, which is along the southern border of the Long Lake lease. Our core-hole analysis and reservoir understanding of Kinosis confirms the resource here has minimal lean zones and shale barriers. Well log and core data show these to be analogous to our best producing wells on Long Lake. Also, with core-holes in place and regulatory approval at an advanced stage, we expect to be able to develop these well pairs faster than for pads beyond 14 and 15. Production from these wells is expected to contribute 15,000 to 25,000 bbls/d at maturity. We expect to provide details regarding timing and cost of this opportunity later this year.
We expect these wells to fill the upgrader and offset production declines in the initial 10 pads.
To further evaluate our Long Lake and Kinosis leases for future development, we are proceeding with a 200 well core-hole drilling program this winter. This program supports our sustaining development activities to keep the Long Lake upgrader full and to begin development of the rest of the Kinosis lease using our bitumen-leading strategy. This strategy allows us to ramp-up SAGD production while retaining flexibility in the timing of building additional upgraders to enhance the economics of the developments.
We are also planning to participate with a 25% working interest in a non-operated SAGD project at Hangingstone. Project sanctioning is expected late this year or early next year, and first steam would be in about late 2014. Our share of production at full rates is expected to be about 6,000 bbls/d.
The upgrader continued to perform well with an on-stream factor of 91% and premium synthetic crude (PSC) yield of 70% compared to 93% and 74%, respectively, in the first quarter. In June, we successfully processed 45,000 bbls/d of produced and purchased bitumen, reaching upgrader throughput of about 65% of capacity. We will continue to purchase and upgrade third-party volumes when market and operating conditions are appropriate.
Shale Gas
Northeast British Columbia – Our shale gas strategy is progressing as planned and production from the eight-well pad at Horn River brought on-stream late last year continues to meet expectations. Horn River production averaged approximately 40 million cubic feet (mmcf/d) during the quarter. Plans to increase production at Horn River later this year continued to progress with our successful drilling program on the nine-well pad, where we once again set industry benchmarks for drilling days per well, including one well drilled in a record 14 days. We also began fracing and completion activities on the wells during the quarter. Production from this nine-well pad is expected on-stream in the fourth quarter but will be limited to our existing facility capacity of about 50 mmcf/d. This capacity increases to 175 mmcf/d in late 2012 to coincide with the start-up of production from our 18-well pad. We commenced drilling this pad in late June and production is expected to come on-stream in the fourth quarter of 2012. Additional facility capacity is planned to be added as our production increases. Our process to seek a joint venture partner to accelerate value realization for a portion of our shale gas asset is proceeding on schedule with numerous parties accessing the data room.
Director Appointments
During the second quarter, Nexen appointed two new directors to our Board, Thomas Ebbern and Arthur Scace, C.M., Q.C. Thomas Ebbern began his career as a geophysicist, and has recently held positions as managing director at Macquarie Capital Markets Canada Ltd., and managing director at Tristone Capital Inc., an energy advisory firm. Arthur Scace comes with a distinguished career in law, where he was former partner and chair of McCarthy Tetrault LLP. He has also sat on various boards, and was the former Chair of the Bank of Nova Scotia.
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable October 1, 2011, to shareholders of record on September 9, 2011.
About Nexen
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. Nexen is focused on three growth strategies: oil sands and shale gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deepwater Gulf of Mexico. Nexen adds value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.
For further information on Appomattox resource disclosure, please refer to our press release dated September 27, 2010.
Conference Call
Marvin Romanow, President and CEO, and Kevin Reinhart, Executive Vice President and CFO, will host a conference call to discuss our second quarter 2011 financial results.
Date: July 14, 2011
Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)
To listen to the conference call, please call one of the following:
416-340-2216 (Toronto)
866-226-1792 (North American toll-free)
800-9559-6853 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 905-694-9451 (Toronto) or 800-408-3053 (toll-free) passcode 6758230 followed by the pound sign.
A live and on demand webcast of the conference call will be available at .
Forward-Looking Statements
Certain statements in this release constitute “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995, as amended) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (together “forward-looking statements”) are generally identifiable by the forward-looking terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook”, “forecast” or other similar words and include statements relating to or associated with individual wells, regions or projects.
Any statements as to possible future crude oil, natural gas or chemicals prices; future production levels; future royalties and tax levels; future capital expenditures, their timing and their allocation to exploration and development activities; future earnings; future asset acquisitions or dispositions; future sources of funding for our capital program; future debt levels; availability of committed credit facilities; possible commerciality of our projects; development plans or capacity expansions; the expectation that we have the ability to substantially grow production at our oil sands facilities through controlled expansions; the expectation of achieving the production design rates from our oil sands facilities; the expectation that our oil sands production facilities continue to develop better and more sustainable practices; the expectation of cheaper and more technologically advanced operations; the expected design size of our operations; the expected timing and associated production impact of facilities turnarounds and maintenance; the expectation that we can continue to operate our offshore exploration, development and production facilities safely and profitably; future ability to execute dispositions of assets or businesses; future sources of liquidity, cash flows and their uses; future drilling of new wells; ultimate recoverability of current and long-term assets; ultimate recoverability of reserves or resources; expected finding and development costs; expected operating costs, future cost recovery oil revenues from our Yemen operations; the expectation of negotiating of an extension to certain of our production sharing agreements; the expectation of our ability to comply with the new safety and environmental rules enacted in the US at a minimal incremental cost, and of receiving necessary drilling permits for our US offshore operations; future demand for chemicals products; estimates on a per share basis; future foreign currency exchange rates, future expenditures and future allowances relating to environmental matters and our ability to comply therewith; dates by which certain areas will be developed, come on stream or reach expected operating capacity; and changes in any of the foregoing are forward-looking statements. Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
All of the forward-looking statements in this release are qualified by the assumptions that are stated or inherent in such forward-looking statements. Although we believe that these assumptions are reasonable, this list is not exhaustive of the factors that may affect any of the forward-looking statements and the reader should not place an undue reliance on these assumptions and such forward-looking statements. The key assumptions that have been made in connection with the forward-looking statements include the following: that we will conduct our operations and achieve results of operations as anticipated; that our development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of our reserve volumes; commodity price and cost assumptions; the continued availability of adequate cash flow and debt and/or equity financing to fund our capital and operating requirements as needed; and the extent of our liabilities. We believe the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; the cumulative impact of oil sands development on the environment; the impact of technology on operations and processes and how new complex technology may not perform as expected; the availability of pipeline and global refining capacity; risks inherent to the operations of any large, complex refinery units, especially the integration between production operations and an upgrader facility; availability of third-party bitumen for use in our oil sands production facilities; labour and material shortages; risks related to accidents, blowouts and spills in connection with our offshore exploration, development and production activities, particularly our deepwater activities; direct and indirect risks related to the imposition of moratoriums, suspensions or cancellations of our offshore exploration, development and production operations, particularly our deepwater activities; the impact of severe weather on our offshore exploration, development and production activities, particularly our deepwater activities; the effectiveness and reliability of our technology in harsh and unpredictable environments; risks related to the actions and financial circumstances of our agents, counterparties, contractors, and joint venture parties; volatility in energy trading markets; foreign currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environmental and other laws and regulations including without limitation, those related to our offshore exploration, development and production activities; renegotiations of contracts; results of litigation, arbitration or regulatory proceedings; political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states; and other factors, many of which are beyond our control.
The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management–s future course of action would depend on our assessment of all information at that time. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the forward-looking statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to the Risk Factors contained in our 2010 Annual Information form, and to the Quantitative Disclosures about Market Risk and our Forward Looking Statements contained in our 2010 Management Discussion and Analysis.
Cautionary Note to US Investors
In this disclosure, we may refer to “recoverable reserves”, “recoverable resources”, “recoverable contingent resources” and “prospective resources” which are inherently more uncertain than proved reserves or probable reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Information Form available under our profile on SEDAR at for further reserves disclosure.
Cautionary Note to Canadian Investors
Nexen has received an exemption from the securities regulatory authorities in the various provinces of Canada from certain requirements of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) that permits us to disclose reserves estimates and related disclosures that have been prepared in accordance with SEC requirements.
As a result of this exemption, Nexen–s disclosures may differ from other Canadian companies and investors should note the following fundamental differences between reserves estimates and related disclosures prepared in accordance with SEC requirements and those prepared in accordance with NI 51-101:
– SEC reserves estimates are based upon different reserves definitions and are prepared in accordance with generally recognized industry practices in the US whereas NI 51-101 reserves are based on definitions and standards promulgated by the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and generally recognized industry practices in Canada;
– SEC reserves definitions differ from NI 51-101 in areas such as the use of reliable technology, areal extent around a drilled location, quantities below the lowest known oil and quantities across an undrilled fault block;
– the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using the year–s monthly average prices and costs held constant whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices and costs;
– the SEC mandates disclosure of reserves by geographic area whereas NI 51-101 requires disclosure of reserves by additional categories and product types;
– the SEC does not require the disclosure of future net revenue of proved and proved plus probable reserves using forecast pricing at various discount rates;
– the SEC requires future development costs to be estimated using existing conditions held constant, whereas NI 51-101 requires estimation using forecast conditions;
– the SEC does not require the validation of reserves estimates by independent qualified reserves evaluators or auditors, whereas, without an exemption noted below, NI 51-101 requires issuers to engage such evaluators or auditors to evaluate, audit or review reserves and related future net revenue attributable to those reserves; and
– the SEC does not allow proved and probable reserves to be aggregated whereas NI 51-101 requires issuers to make such aggregation.
The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material for certain properties. Please also note:
– we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; and
– because reserves data are based on judgments regarding future events actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery.
Nexen has also received an exemption from NI 51-101 that permits us to forego the requirement to have our reserves and related future net revenue attributable to our reserves evaluated, audited or reviewed by an independent qualified reserves evaluator or auditor. Accordingly, our future net revenue and reserves estimates are based on internal evaluations. Due to the extent and expertise of our internal reserves evaluation resources, our staff–s familiarity with our properties and the controls applied to the evaluation process, we believe the reliability of our internally generated reserves estimates is not materially less than would be generated by an independent reserves evaluator.
Resources
The resource estimates contained in this news release were announced on September 27, 2010 and were prepared by qualified reserves evaluators. The estimated contingent and prospective resources in this news release reflects all of our low, high and best case of recoverable resources. A “best estimate” is the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The –low estimate– and –high estimate– are considered to be conservative and optimistic estimates of resources with 90% and 10% confidence respectively. Nexen–s estimates of contingent and prospective resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook. Contingent resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Prospective resources are quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.
Contingencies on resources may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific oil sands contingencies precluding these contingent resources being classified as reserves include but are not limited to: project sanction, the cost and effectiveness of steam-assisted gravity drainage application, stakeholder and regulatory approvals, access to required services and infrastructure, oil prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent oil sands resources.
Specific shale gas contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program and testing results, project sanction, the cost and effectiveness of fracing optimization, stakeholder and regulatory approvals, access to required services and field development infrastructure, gas prices and a demonstration of economic viability. There is no certainty that it will be commercially viable to produce any portion of these contingent shale gas resources. In the case of shale gas prospective resources there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Nexen Inc.
Notes to Unaudited Condensed Consolidated Financial Statements
Cdn$ millions, except as noted
1. BASIS OF PRESENTATION
Nexen Inc. (Nexen, we or our) is an independent, global energy company with operations in the North Sea, Gulf of Mexico, offshore West Africa, Canada, Yemen and Colombia. Nexen is incorporated and domiciled in Canada. Nexen–s shares are publicly traded on both the Toronto Stock Exchange and the New York Stock Exchange.
These Unaudited Condensed Consolidated Financial Statements for the three and six months ended June 30, 2011 have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting. The Unaudited Condensed Consolidated Financial Statements do not include all of the information required for annual financial statements. Amounts relating to the three and six months ended June 30, 2010 and as at December 31, 2010 were previously presented in accordance with Canadian GAAP. These amounts have been restated as necessary to be compliant with our accounting policies under International Financial Reporting Standards (“IFRS”) (see Note 2). Reconciliations and descriptions relating to the transition from Canadian GAAP to IFRS are included in Note 17.
The Unaudited Condensed Consolidated Financial Statements were authorized for issue on July 13, 2011 and should be read in conjunction with the Audited Consolidated Financial Statements for the year ended December 31, 2010, which have been prepared in accordance with Canadian GAAP.
2. ACCOUNTING POLICIES
The accounting policies we follow are described in Note 2 of the Unaudited Condensed Consolidated Financial Statements for the three months ended March 31, 2011.
Future Changes in Accounting Policies
As part of our transition to IFRS, we will adopt all IFRS accounting standards in effect on December 31, 2011.
The following standards and interpretations have not been adopted as they apply to future periods. They may result in future changes to our existing accounting policies and other note disclosures. We are currently evaluating the impact that these standards will have on our results of operations and financial position:
Exploration and evaluation assets mainly comprise of unproved properties and capitalized exploration drilling costs. Assets under construction include our Usan development, offshore Nigeria.
(b) Impairment
Our DD&A expense for 2010 includes non-cash impairment charges of $139 million for properties in the US Gulf of Mexico and Canada. In the second half of 2010, low natural gas prices, higher estimated future abandonment costs and declining production performance reduced properties– estimated future cash flows, which resulted in impairments for properties in the US Gulf of Mexico and Canada.
These properties were written down to their estimated fair value based on their estimated future discounted net cash flows. The estimated future cash flows incorporate a risk-adjusted discount rate and management–s estimates of future prices, capital expenditures and production.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
(a) Term credit facilities
We have unsecured term credit facilities of $3 billion (US$3.1 billion) available until 2016, none of which were drawn at either June 30, 2011 or December 31, 2010. Borrowings are available as Canadian bankers– acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. During the six months ended June 30, 2011, we did not incur any interest expense on our term credit facilities. The weighted-average interest rate on our term credit facilities for the three months ended June 30, 2010 was 1.3% and 1.1% for the six months ended June 30, 2010. At June 30, 2011, $279 million (US$289 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2010 – $322 million (US$324 million)).
(b) Redemption of Notes, due 2013
During the quarter, we redeemed and cancelled US$500 million of principal from bonds due in 2013. We paid $525 million for the redemption. We recorded a $52 million loss during the first quarter as the difference between carrying value and the redemption price.
(c) Repurchase for Cancellation of Certain 2015 and 2017 Notes
In the first quarter, we repurchased and cancelled US$124 million and US$188 million of principal from the 2015 and 2017 bonds, respectively. We paid $346 million for the repurchase and recorded a $39 million loss as the difference between carrying value and the redemption price.
(d) Short-term borrowings
Nexen has uncommitted, unsecured credit facilities of approximately $463 million (US$481 million), none of which were drawn at either June 30, 2011 or December 31, 2010. We utilized $24 million (US$25 million) of these facilities to support outstanding letters of credit at June 30, 2011 (December 31, 2010-$112 million (US$112 million)). Interest is payable at floating rates.
8. FINANCE EXPENSE
Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings.
9. ASSET RETIREMENT OBLIGATIONS (ARO)
Changes in the carrying amount of our ARO provisions are as follows:
ARO represents the present value of estimated remediation and reclamation costs associated with our PP&E. We have discounted the estimated asset retirement obligation using a weighted-average risk-free rate of 3.0% (2010-3.3%). While the provision for abandonment is based on our best estimates of future costs and the economic lives of the assets involved, there is uncertainty regarding both the amount and timing of incurring these costs. We expect approximately $367 million included in our ARO will be settled over the next five years with the balance settling beyond that. We expect to fund ARO from future cash flows from our operations.
10. RELATED PARTY DISCLOSURES
Major subsidiaries and joint ventures
The Unaudited Condensed Consolidated Financial Statements include the financial statements of Nexen Inc. and our subsidiaries as at June 30, 2011. The following is a list of the major subsidiaries of our operations. Transactions between subsidiaries are eliminated on consolidation. Nexen did not have any material related party transactions with entities outside the consolidated group in the six months ended June 30, 2011 and 2010.
11. EQUITY
(a) Common Shares
Authorized share capital consists of an unlimited number of common shares of no par value and an unlimited number of Class A preferred shares of no par value, issuable in series. At June 30, 2011, there were 527,014,110 common shares outstanding (December 31, 2010 – 525,706,403 shares; January 1, 2010 – 522,915,843 shares). There were no preferred shares issued and outstanding (December 31, 2010 – nil; January 1, 2010 – nil).
(b) Dividends
Dividends paid per common share for the three months ended June 30, 2011 were $0.05 per common share (three months ended June 30, 2010 – $0.05). Dividends per common share for the six months ended June 30, 2011 were $0.10 per common share (six months ended June 30, 2010 – $0.10). Dividends paid to holders of common shares have been designated as “eligible dividends” for Canadian tax purposes. On July 13, 2011, the Board of Directors declared a quarterly dividend of $0.05 per common share, payable October 1, 2011 to the shareholders of record on September 9, 2011.
12. COMMITMENTS, CONTINGENCIES AND GUARANTEES
As described in Note 15 to the 2010 Audited Consolidated Financial Statements, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We believe that payments, if any, related to existing indemnities, would not have a material adverse effect on our liquidity, financial condition or results of operations.
We assume various contractual obligations and commitments in the normal course of our operations. During the quarter, we entered into new drilling rig commitments in the UK North Sea and made additional office lease commitments, comprised of the following:
The commitments above are in addition to those included in Note 15 to the 2010 Audited Consolidated Financial Statements. Our operating leases, transportation and storage commitments, and other drilling rig commitments as at June 30, 2011 have not materially changed from the information previously disclosed in our 2010 Audited Consolidated Financial Statements.
13. MARKETING AND OTHER INCOME
14. DISCONTINUED OPERATIONS
In February 2011, we completed the sale of our 62.7% investment in Canexus Limited Partnership, which operates a chemicals business, for net proceeds of $458 million and we realized a gain on disposition of $348 million in the first quarter. In the fourth quarter of 2010, we received board approval to sell our interest in Canexus and classified the assets and liabilities as held for sale at December 31, 2010. The gain on sale and results of our chemicals business have been presented as discontinued operations.
In July 2010, we completed the sale of our heavy oil properties in Canada. We received proceeds of $939 million, net of closing adjustments and realized a gain on disposition of $828 million in the third quarter of 2010. The gain on sale and results of operations of these properties have been presented as discontinued operations.
The following table provides the assets and liabilities that are associated with our chemicals business at December 31, 2010 and January 1, 2010. There were no assets or liabilities related to our chemical operations at June 30, 2011.
16. OPERATING SEGMENTS AND RELATED INFORMATION
Effective in the first quarter of 2011, we amended our segment reporting to reflect changes in our business. In 2010, we disposed of non-core operations including heavy oil operations in Canada, chemicals and certain energy marketing businesses, and ramped up production at Long Lake. We report our segments to align with our key growth strategies, specifically, Conventional Oil and Gas, Oil Sands and Unconventional Gas. Prior period results have been revised to reflect the presentation changes made in the current period.
Nexen has the following operating segments:
Conventional Oil and Gas: We explore for, develop and produce crude oil and natural gas from conventional sources around the world. Our operations are focused on the UK, North America (Canada and US) and other countries (Yemen, offshore West Africa and Colombia).
Oil Sands: We develop and produce synthetic crude oil from the Athabasca oil sands in northern Alberta. We produce bitumen using in situ and mining technologies and upgrade it into synthetic crude oil before ultimate sale. Our in situ activities are comprised of our operations at Long Lake and future development phases. Our mining activities are conducted through our 7.23% ownership of the Syncrude Joint Venture.
Unconventional Gas: We explore for and produce unconventional gas from shale formations in northeastern British Columbia and Poland. Production and results of operations are included within Conventional Oil and Gas until they become significant.
Corporate and Other includes energy marketing, unallocated items and the results of Canexus prior to its sale in February 2011. Canexus manufactures, markets and distributes industrial chemicals, principally sodium chlorate, chlorine, muriatic acid and caustic soda. The results of our chemicals business have been presented as discontinued operations.
The accounting policies of our operating segments are the same as those described in Note 2. Net income of our operating segments excludes interest income, interest expense, unallocated corporate expenses and foreign exchange gains and losses. Identifiable assets are those used in the operations of the segments.
Segmented net income for the three months ended June 30, 2011
17. TRANSITION TO IFRS
For all periods up to and including the year ended December 31, 2010, we prepared our Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles (Canadian GAAP). As a publicly listed company in Canada, we are required to prepare consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) for all periods after January 1, 2011 including comparative historical information. As we are also publicly listed in the United States, we were required to include a reconciliation of our financial results between Canadian GAAP and US GAAP. The reconciliation to US GAAP is no longer required.
In accordance with transitional provisions, we prepared our opening balance sheet as at January 1, 2010 (the transition date) and 2010 comparative financial information using the accounting policies set out in Note 2. The consolidated financial statements for the year ended December 31, 2011 will be the first annual financial statements that comply with IFRS by applying existing IFRS with an effective date of December 31, 2011 or earlier. This transition note explains the material adjustments we made to convert our financial statements to IFRS.
Elected Exemptions from Full Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1 First-time Adoption of International Financial Reporting Standards (IFRS 1), we applied the following optional exemptions from full retrospective application of IFRS.
(i) Business Combinations
We applied the business combinations exemption to not apply IFRS 3 Business Combinations retrospectively to past business combinations. Accordingly, we have not restated business combinations that took place prior to the transition date.
(ii) Fair Value or Revaluation as Deemed Cost
We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet.
(iii) Cumulative Translation Differences
We elected to set the cumulative translation account, which is included in accumulated other comprehensive income, to nil at January 1, 2010. This exemption has been applied to all subsidiaries.
(iv) Share-based Payment Transactions
We elected to use the IFRS 1 exemption whereby the liabilities for share-based payments that had vested or settled prior to January 1, 2010 were not required to be retrospectively restated.
(v) Employee Benefits
We elected to apply the exemption for employee benefits to recognize the accumulated unrecognized net actuarial loss in retained earnings at January 1, 2010. This exemption has been applied to all defined benefit pension plans.
(vi) Asset Retirement Obligations
We applied the exemption from full retrospective application of our asset retirement obligations as permitted for first-time adoption of IFRS. As such, we re-measured ARO as at January 1, 2010. We estimated the amount to be included in the related asset by discounting the liability to the date when the obligation first arose using our best estimates of the historical risk-free discount rates applicable during the intervening period.
(vii) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to retained earnings.
Mandatory Exceptions to Retrospective Application
In preparing these Unaudited Condensed Consolidated Financial Statements in accordance with IFRS 1, we were required to apply the following mandatory exceptions from full retrospective application of IFRS.
(i) Hedge Accounting
Only hedging relationships that satisfied the hedge accounting criteria as of the transition date are reflected as hedges in our results under IFRS. Any derivatives not meeting the IAS 39 Financial Instruments: Recognition and Measurement criteria for hedge accounting were recorded as a non-hedging derivative financial instrument.
(ii) Estimates
Hindsight was not used to create or revise estimates and accordingly, our estimates previously made under Canadian GAAP are consistent with their application under IFRS.
Reconciliations of Canadian GAAP to IFRS
IFRS 1 requires the presentation of a reconciliation of shareholders– equity, net income, comprehensive income, and cash flows for prior periods. The transition from Canadian GAAP to IFRS had no material effect upon previously reported cash flows. The following represents the reconciliations from Canadian GAAP to IFRS for the respective periods for shareholders– equity, net income, and comprehensive income:
Reconciliation of Shareholders– Equity
(i) Borrowing Costs
We applied the IFRS 1 exemption to prospectively capitalize borrowing costs from the transition date as described above.
(ii) Asset Retirement Obligations (ARO)
We applied the IFRS 1 exemption for asset retirement obligations and re-measured our ARO as at January 1, 2010 as described above.
(iii) Employee Benefits
We have chosen to include previously unrecognized actuarial gains and losses of our defined benefit pension plans on the balance sheet under IFRS. Under Canadian GAAP, we amortized actuarial gains and losses to income over the estimated average remaining service life, with disclosure of the unrecognized amount in the notes to the Consolidated Financial Statements. On January 1, 2010, we applied the IFRS 1 exemption to recognize the accumulated unrecognized net actuarial loss in retained earnings on transition to IFRS.
(iv) Stock-Based Compensation (SBC)
Under Canadian GAAP, we recorded obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. IFRS requires that we record these SBC obligations at fair value and subsequently re-measure the obligation each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. On transition, we recorded the liability at fair value for unsettled awards.
(v) Property Plant and Equipment
Impairment
Under Canadian GAAP, if indications of impairment exist and the asset–s estimated undiscounted future cash flows were lower than it–s carrying amount, the carrying value was written down to fair value. Under IFRS, if indications of impairments exist, the asset–s carrying value is immediately compared to its estimated recoverable amount, which could trigger additional impairment under IFRS. We elected to measure certain producing oil and gas properties at fair value as at the transition date and use that amount as its deemed cost in the opening IFRS balance sheet. As a result, oil and gas properties were written down to fair value of $460 million and resulted in an impairment expense of $91 million on transition.
Componentization
Under Canadian GAAP, we depleted oil and gas capitalized costs using the unit-of-production method on a field-by-field basis and depreciated non-resource capitalized costs based on their estimated useful life. On adoption of IFRS, we reviewed our PP&E to identify each material component that has a significantly different useful life and as a result, adjustments to the accumulated depletion of certain assets were required on transition to IFRS.
Major Maintenance
Under Canadian GAAP, operating expenses included major maintenance costs that were expensed as incurred. Under IFRS, these costs are capitalized and depreciated separately until the next planned major maintenance project.
(vi) Foreign Exchange
Foreign Currency Translation
We applied the first-time IFRS adoption exemption to reset our cumulative translation differences to nil on the transition date. Accumulated foreign exchange gains and losses of our self-sustaining foreign operations, net of foreign exchange translation gains and losses of long-term debt designated as hedges are included in retained earnings on the transition date. This one-time adjustment had no impact on shareholders– equity on transition.
Change in Functional Currency
As a result of additional guidance under IFRS, our assessment of the functional currency of a subsidiary changed from Canadian dollars to US dollars to better reflect the economic environment in which it operates.
(vii) Long-Term Debt
Canexus Convertible Debentures
Canexus unitholders have the ability to redeem fund units for cash pursuant to the terms of the trust indenture. Under IFRS, these convertible debentures are considered to be financial liabilities containing an embedded derivative. Under Canadian GAAP, the convertible debentures were considered to be compound instruments with an equity component. Accordingly, the equity component and unamortized deferred transaction costs recorded under Canadian GAAP were derecognized on January 1, 2010 and charged to retained earnings. We elected to recognize the convertible debentures at fair value and to recognize changes in fair value in net income during the period of change.
(viii) Income Taxes
Recognition of Deferred Tax Credit
In 2008, we completed an internal reorganization and financing of our assets in the North Sea, which provided us with a one-time tax deduction in the UK. Canadian GAAP precluded us from recognizing the full estimated benefit of the tax deductions until the assets were recognized in net income either by a sale or depletion through use. As a result, we deferred the initial recognition of the benefit and were amortizing it to future income tax expense over the life of the underlying assets under Canadian GAAP. On adoption of IFRS, no such prohibition exists and we recognized the remaining deferred tax credit in retained earnings on transition to IFRS.
Exceptions
Under Canadian GAAP, deferred taxes were generally provided on all temporary differences. Conversely, IFRS does not recognize deferred taxes on temporary differences arising from the initial recognition of assets or liabilities in transactions that are not business combinations and that affect neither accounting nor taxable profit or loss.
Reconciliation of Net Income
(i) Borrowing Costs
We applied an IFRS transitional exemption to prospectively capitalize borrowing costs from the transition date. As a result, borrowing costs previously capitalized under Canadian GAAP were expensed to shareholders– equity. The reduced capitalized amounts decreased DD&A expense during 2010.
(ii) Asset Retirement Obligations (ARO)
Under Canadian GAAP, foreign exchange translation gains and losses arising from the revaluation of GBP-denominated asset retirement obligations were included in net income in the period in which they occurred. Under IFRS, these translation gains and losses are treated as a change in estimate and therefore increase or decrease PP&E with a corresponding impact on net income.
(iii) Stock-Based Compensation (SBC)
As described above, we record obligations for liability-based stock compensation plans at fair value each reporting period. Our tandem option, stock appreciation rights and restricted share unit plans are considered liability-based stock compensation plans. The changes in the SBC fair value in 2010 were recognized in net income.
(iv) Property Plant and Equipment
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