A final decision on whether to move forward with the massive LNG Canada export project has been "pushed out to the future," while unconventional oil and natural gas projects are on the longer-term list, Royal Dutch Shell plc CEO Ben van Beurden said Thursday.
Shell and a consortium of Asian partners hold a license from Canada's National Energy Board to export up to 3.2 Bcf/d of liquefied natural gas (LNG) from Kitimat in British Columbia, and last year the project received formal environmental approval (see Daily GPI, June 18, 2015; Feb. 14, 2014). A final investment decision was scheduled early this year (see Daily GPI, Nov. 10, 2014).
The combination with BG plc, another big integrated gas operator, remains scheduled to be completed by Feb. 15 (see Daily GPI, Jan. 28). BG already has a host of LNG projects in the works, and cutbacks have to be made, van Beurden said during a quarterly conference call.
"Only the most competitive projects are going ahead," he said. "Many potential projects have been purposely delayed, resized or canceled altogether. And this is to manage affordability and to get better value from the supply chain in this downturn."
Shell last year pulled the trigger on only four major investments, with Appomattox in the deepwater Gulf of Mexico (GOM) the only upstream project to get the green light (see Daily GPI, July 1, 2015). Shell also plans to sell another $30 billion of assets between 2016 and 2018 as BG is consolidated into the portfolio, with 2016 sales likely to total less than $10 billion. Assets on the market are to include midstream, downstream and "local gas markets," as well as master limited partnership and private equity stakes.
Building a large, diversified LNG portfolio remains the plan longer term because global gas demand is growing about 2.3% a year over the past decade, the CEO said.
"But LNG is still only 10% of the overall total gas demand...It's becoming clear that although the medium-term outlook for LNG demand growth in China is robust, in the near-term, the LNG demand growth is slowing there, and potentially in some other countries. It's really important to look at the development of the global LNG market overall."
Today, 30 countries are importing LNG and 20 are exporting, which should grow to 50 importers and 25 exporters in the early 2020s, according to van Beurden. And Shell is making progress with the LNG project it already has in hand. Last year it signed LNG sales deals, typically for 10 years or longer, for about 4 million metric tons/year, all linked to oil prices. More than 85% of Shell's LNG contracts are linked to oil prices. Last year Shell also completed more than 10 scheduled contract price reviews for Asia-Pacific joint ventures "that reinforced traditional LNG contracts," and opened access to new markets.
"The completion of the BG transaction...marks the start of a new chapter in Shell, rejuvenating the company, and improving shareholder returns," he said. With the combination, "Shell is becoming a company that is more focused on its core strength, a company that is more resilient and competitive at all points in the price cycle" with a "more predictable development pipeline."
The European oil major plans to keep "pulling on powerful financial levers...to keep a sensible and high-value investment program under way for the future." To that end, deepwater and integrated gas projects take precedence with the BG merger. Conventional oil and gas, downstream and chemicals also will take a bigger chunk of capital investments. Between 2016 and 2020, only one U.S. project appears to be on the short list for ramp-up, Stones, which also is in the deepwater GOM (see Daily GPI, Sept. 8, 2014). That priority list could change, said the CEO, depending on market conditions.
"Longer-term potential" exists for shales, which is only a small slice of Shell's business today, while Canada's heavy oil also is on the back-burner. During the conference call, van Beurden never mentioned shale or unconventionals, only giving a nod to the long list of delayed or deferred projects.
Late in December Shell sharply reduced capital expenditure (capex) plans for 2016 to $33 billion total, including BG, down $12.5 billion from 2015 (see Daily GPI, Dec. 23, 2015). The capex plan, however, could be cut even more, as "options are on the table to further reduce...should conditions warrant," van Beurden said. Shell management won't know exactly how capex may play out this year until it is able to "look under the hood" of BG's operations.
Shell earned an estimated $939 million in the final three months of 2015, 58% lower than in the year-ago period, but sharply higher than in 3Q2015, when losses totaled $7.4 billion. On a current cost of supplies (CCS) basis, which strips out one-time items and is similar to U.S. net earnings, profits totaled $1.8 billion (29 cents/share), down 44% year/year. Full-year CCS earnings were $3.8 billion, a year/year decline of 80%. Operating cash flow in the latest period fell 44% to $5.4 billion. The gearing ratio, indicative of leverage, at year-end 2015 was 14%, versus 12.2% at the end of 2014.
Upstream profits took it on the chin, expected on the commodity price strafing, falling to $493 million from 4Q2014 profits of $1.73 billion. Earnings included a net charge of $826 million, primarily reflecting asset impairments totaling $640 million and hedging losses of $219 million. Downstream profits year/year were nearly flat at $1.524 billion from $1.55 billion.
In the Americas, the upstream business saw global liquids realizations slump 46% from 4Q2014. Global natural gas realizations from the year-ago quarter were 33% lower, while prices received for gas in the Americas fell 44%.
Operating costs fell by $4.1 billion last year to $41.1 billion. Costs are slated to decline again this year by an estimated $3 billion, 15% below 2014 levels. Synergies from the BG combinations would be in addition to those reductions. The return on average capital employed was 1.9% at the end of 2015, versus 7.1% at year-end 2014.
Oil and natural gas production in the last three months of 2015 fell by 5% from a year earlier to an average of 3.04 million boe/d, in line because of the impact of divestments and curtailments. For the year, production declined 4% to average 2.95 million boe/d. Two big fields that ramped up last year in the deepwater GOM, Mars B and Cardamom, contributed to an 88,000 boe/d production gain from 4Q2014.
Natural gas production available for sale declined 11% in the quarter to 8.741 Bcf/d from 9.782 Bcf/d. For the year, gas output fell 9%. Equity LNG sales were down 8% to 5.68 million metric tons, with full-year sales off 6%. Oil sales volumes declined 1%, while chemical sales rose 7%.
One notable loss, expected with the price downturn, was in the reserves replacement ratio, with Shell's estimated proved reserves dropping 20% from 2014, a reduction of 1.4 billion boe. When final volumes are reported in the annual report and U.S. Securities and Exchange Form 20-F, proved oil and gas reserves are expected be down by 0.2 billion boe from 2014.