This article is based on a presentation made at a CHOA event at the Calgary Petroleum Club on October 18, 2019. The views expressed in the article are the author’s own and are not to be construed as CHOA’s or GLJ’s opinions on this subject.
On December 2, 2018, the Alberta provincial government announced legislation to temporarily curtail oil production in Alberta effective January 1, 2019. The announcement was met with wide-ranging opinions on the need for and efficacy of the intervention. Curtailment has, not surprisingly, remained a topic for debate and discussion throughout 2019. Looking back on the year, we can now draw some conclusions on benefits, costs, winners and losers. Before we get to that, let’s recap the lead-up to the announcement, unintended consequences and the industry’s response.
How did we get here? – The trigger
The chart below neatly depicts the direct trigger for the legislation, explicitly the blown-out differentials on Canadian oil in October and November 2018. Over the previous five years, the price difference between West Texas Intermediate (WTI) and Western Canadian Select (WCS), otherwise known as the WTI-WSC differential, has been in the range of 15-20 USD/barrel. 10 to 15 years ago, the WTI-WCS differential was even lower at about 10-15 USD/barrel. During this period, Alberta’s oil production growth outpaced the addition of pipeline egress and US oil production more than doubled. By 2018, Alberta’s production had exceeded pipeline egress. This resulted in increased crude by rail shipments and, when combined with a US Midwest refinery outage in the fall, Albertan oil supply was backed up within our borders. This backup lead to a WTI-WCS differential of 45 USD/bbl in November 2018.
Importantly, the supply–egress imbalance also affected the Edmonton Mixed Sweet Blend (MSW) prices. Historically, MSW sold at a very tight differential to WTI, but in November 2018, this differential increased to almost 27 USD/barrel.
The situation was not sustainable. Many companies were already voluntarily curtailing production given low and, in certain instances, negative wellhead prices. In November 2018, the Canadian Association of Petroleum Producers (CAPP) estimated that, as a result of the differentials, the economy had lost 13 billion dollars in the first ten months of 2018, including 50 million dollars per day in October. The Alberta government, using a Scotiabank methodology, estimated that the discount on Canadian oil cost the Canadian economy more than 80 million dollars per day. While uncertainty around the estimates of lost revenue remains, it was clear that October-November 2018 prices would cost both the industry and the Alberta government, partners in our resource development, billions of dollars.
But how did we get here? In truth, if our markets were functioning properly, curtailment would not have been required and, it’s not just a market access problem. The figure below depicts many challenges faced by the Canadian oil industry over the last decade. These challenges include changes to the Investment Canada Act, our “dirty oil” label, long and uncertain project approval timelines and a lack of investment inflows culminating, most recently, in a disconnect between Canadian E&P valuations and commodity prices. So, market access alone won’t be the silver bullet we need to right the market. In the words of Alex Pourbaix, CEO of Cenovus, “These are not ordinary circumstances.” It has taken us over a decade to get into this predicament. It will likely take a similar amount of time to get out.
Premier Notley announced curtailment on December 2, 2018, noting that “Alberta currently produces 190,000 bpd more than can be shipped using existing pipeline and rail capacity”. Curtailment would apply to operators producing more than 10,000 bpd, the AER would implement curtailment, and it would be temporary.
The government’s excess supply calculation was provided as:
As a result, the government originally set the production curtailment volume at 325,000 bpd, first, to eliminate the supply-egress imbalance and, second, to also address high storage levels late in 2018. Curtailment was designed to narrow the differential, reduce price volatility, and augment 2019 government revenue relative to what it would have occurred otherwise.
The Order in Council details the purpose of the legislation as follows:
- to effect conservation and prevent wasteful operations
- to prevent improvident disposition, and
- to ensure the economic development in the public interest of the crude bitumen and crude oil resources of Alberta
While there were wide-ranging opinions on curtailment, they can be succinctly summed up as “reluctant acceptance of market intervention” with one CEO describing it as “difficult but necessary.”
Basic Curtailment Calculation
The figure below provides the formula for determining curtailment. There are two key components: first, determining the operators’ adjusted baseline (that is, their baseline after the 10,000 bpd exemption). And second, determining the allowable percentage production of the aggregate adjusted baseline for all operators with an adjusted baseline greater than zero, or, in other words, the aggregate adjusted baseline for all curtailed operators. Then, for each operator, that allowable percentage is applied to their adjusted baseline, and the 10,000 bpd exemption is added back to provide their production limit.
The following figure shows an example for a 50,000 bpd production baseline. Based on the February-March target set by the government, the operator would be curtailed to under 45,000 bpd – a little over 10% below their baseline.
One key detail that wasn’t clarified at the time of the announcement was how the production baseline would be established for each operator. The Alberta government’s Information Letter 2018-40 specified that an operator’s baseline was to be based on their six highest individual months of production between November 2017 and October 2018. As a result, 25 operators were required to curtail a portion of the 8.7% of curtailed production in Alberta.
Unintended consequences were evident from the very beginning. Only one week after the announcement, a change was made to introduce temporary production thresholds as detailed in the Alberta government’s Information Letter 2018-41. It was clear that under the original rules, companies in the process of ramping up production were more substantially impacted than companies with stable production or production that had already been voluntarily curtailed. In other words, companies that had made recent capital investments were being disproportionately curtailed. As a result, for January 2019, operators with production levels 16% or higher relative to their October 2018 production had their allowables adjusted upwards. The government also noted that industry had expressed concerns that curtailment had the potential to impact safety or cause long term damage to resources. Consequently, the Production Curtailment Issues Panel was established to address industry concerns.
Next on December 20, (Information Letter 2018-43) details were provided on the process for consolidation or transfer of allowables between two or more curtailed operators and on December 30 (Information Letter 2018-46), the government updated the curtailment rules effective February 2019 changing the calculation of operator baseline by using the single highest month of production from November 2017 to October 2018. This was to account for recent capital investments, operators with increasing production with very few options for curtailment within their portfolio, and to address the possibility of long-term reservoir damage or safety issues. In general, this shifted curtailment from companies with recent increases in production to companies with stable or voluntarily curtailed production and this also had the effect of increasing the number of operators curtailed to 29.
At the end of January 2019, two more changes were implemented (Information Letter 2019-05). The first was to address operators with a high percentage (more than 80%) of freehold production. In this case, in the event that the operator couldn’t meet their contractual obligations, their limit would be adjusted upwards. The second was to address the potential for long term impairment: If an in situ project makes up more than 80% of the total 2019 production forecast for an operator if the operator has recently started injecting into at least one well within that project, if the operator’s 2019 production forecast is expected to be 125% or more than their 2018 production forecast., and lastly, if the operator can demonstrate that compliance would result in long term damage, then their curtailment limit would be adjusted upwards. These changes effectively put a framework around criteria for limit changes for companies with reliance on single projects in growth mode. There were some more changes at the end of February (Information Letters 2019-09 and 2019-10), which were largely administrative, providing a new process for consolidation and transfer by extending the deadline for transfers to allow for production true-up at the end of the month.
All of this built to the most recent changes (as of the date of the original presentation of this material on October 18, 2019) on August 20 (Information Letter 2019-28) when the newly elected provincial government extended curtailment to the end of 2020 as a result of continued pipeline delays, notably the estimated one year delay of Enbridge’s Line 3 Replacement to H2 2020. At the same time, the government increased the exemption to 20,000 bpd effective October 2019, reducing the number of companies curtailed to 16.
Unmistakably the adjustments to the curtailment rules between early December 2018 and the end of August 2019 represent the government’s response to early unintended consequences as identified by industry. But, let’s take a look at some additional observable unintended consequences. Upon implementation of curtailment in January 2019, the figure below, for instance, shows a surprisingly rapid and dramatic contraction in the differentials to unexpectedly low levels. The WTI-MSW differential dropped to less than 5 USD/bbl, and the WTI-WCS differential hovered around 10 USD/bbl.
The result? The economics for rail transportation effectively evaporated with the WTI-WSC differential too narrow to support rail costs of 15-22 USD/bbl. Consequently, as shown below, rail utilization dropped, and storage levels increased, counter to the stated goals of the curtailment legislation.
The above chart shows in light blue the Alberta government allowables for each month. The difference between the orange and blue lines represent the curtailed production. As can be seen, the government increased the allowables between January and February 2019. This was done in response to some previously mentioned unintended consequences and the quick unanticipated contraction in the differential, which in turn coincided with the drop in rail utilization.
Storage started in late 2018 at 35 MMbbl, increased to 37 MMbbl early in January, and subsequently declined, with curtailment in place, to 28 MMbbl by the end of February. However, with rail capacity mostly offline in February and March, the storage built to a high of over 37 MMbbl in April. As the government eased curtailment, the differentials have widened a bit further to 12-13 USD/bbl and rail has come back online, decreasing storage to 26 MMbbl at the end of August. One might wonder how the 12-13 USD/bbl can support rail. The answer lies in the fact that US gulf coast prices have popped up relative to WTI – sitting about 5-6 USD/bbl higher. Together with the differential, this makes rail economic for at least some operators.
A decrease to new oil wells on-stream (a proxy for drilling activity) has been another unintended consequence. In the chart below, the solid lines are historical prices, and the dotted lines are well-counts. It is notable that Alberta has been harder hit than Saskatchewan over the past decade. While the 2015 drop in oil wells on-stream was clearly directly related to price, in Alberta the drop was almost certainly exacerbated by the ill-timed royalty review, the increase in corporate taxation, the imposition of the cap on oil sands emissions, the increase in the specified emitters levy, and the carbon tax.
As prices rebounded, so have the well-counts; until 2019, where we see a disconnect with price, paralleling the share price disconnect in the publicly traded oil and gas market. Both Alberta and Saskatchewan have seen contraction to lowest levels, but Alberta, again, is worse off, and curtailment is almost certainly a part of this.
In July, the Petroleum Services Association of Canada (PSAC) modified their 2019 drilling forecast for Alberta to ~2400 wells, down over 30% from original estimates. Their stated reasons were curtailment and low gas and liquids prices. More recently on, August 20, the Conference Board of Canada provided an updated outlook for Alberta, indicating that we would be in recession in 2019, with 0.8% contraction in our economy. This contraction increased eight-fold from their earlier estimate of 0.1% in May 2019. They also noted that construction and drilling would be hit hardest with 10 and 30 percent declines, respectively.
As seen in the following chart, one surprising outcome is that oil sands delineation wells actually increased in 2019. The big players appear to be progressing their long-term plans despite curtailment, which could suggest they believe that curtailment will be short-lived. It is also interesting that the “Big 7” make up almost 100% of delineation wells; the “Big 7” defined in this context as CNRL, Cenovus, ConocoPhillips, Husky, Imperial, MEG and Suncor. Junior oil sands operators’ delineation efforts fell off sharply since 2013, coinciding with foreign capital pulling back, sharp capital cost inflation and some disappointing results in Central and West parts of the Athabasca Oil Sands Region.
Not surprisingly, one of the curtailments’ biggest effects has been on growth. CNRL is currently the only company with a new project on-stream – Kirby North with first oil in May. All other projects either have uncertain timing or have been delayed, and a number of previously planned greenfield projects have been cancelled. In August 2019, the Alberta Energy Regulator (AER) released the June data for thermal in-situ production. Thermal production will see its first annual decline in 2019 since 2002, primarily due to curtailment.
Winners and Losers
So, who are the winners and losers? From a short-term or tactical perspective, higher prices have had wide-reaching benefits. Oil and gas companies have benefited from higher revenues and cash flow, Albertans have benefited with increased royalties and taxes flowing to government and, potentially, fewer job losses, and Canadians have benefited from increased taxes and equalization payments. By protecting cashflow for the operators, the service companies have also ended up better than they would have otherwise.
The potential losers? Certainly, companies with higher levels of integration, including downstream refining businesses – Husky, Imperial and Suncor all spoke up against curtailment – have given up some of their downstream margins as a result of higher feedstock costs. But did they lose more downstream than what they gained upstream? This is unclear.
From a relative perspective, the curtailed companies themselves are arguably losers. Although, curtailment was designed with a small volume decrease, which we now know has been offset by a large price increase. That said, as for the integrated companies, curtailed companies that had already protected themselves with firm service, hedges, storage, etc., likely haven’t seen the same benefit as those who had not.
Clearly, as already described, rail companies have seen business pull back in the first half of 2019. One might also expect that the mid-streamers with feeder lines to the main hubs would have shipped less volume, but the reality is that we don’t know what would have been voluntarily curtailed anyway. Perhaps they aren’t any worse off.
Of particular note, oil futures traders took a hit as a result of the announcement., highlighting concerns around diminished investor confidence, a willingness to invest in the face of jurisdictional unpredictability and the idea of government re-distributing market pain as they see fit.
As a short-term tactic, the benefits of curtailment might appear to out-way the costs, but is this true from a longer-term strategic perspective? Are all of the winners ultimately actually losers? Have we given up more than we realize?
While curtailment has worked to collapse differentials, it has, in fact, removed or severely limited market forces that would enable or promote self-correction. Prior to curtailment, the market was in the process of re-balancing naturally. Companies were curtailing voluntarily, arguably shutting in the highest cost production first, and rail was on the rise. No doubt that without curtailment, the differentials would have remained painfully wide for longer. But there would also have been strong incentives for further expansion of rail, more storage additions, and further pipeline optimization.
With curtailment in place, we sit in a holding pattern. A no-growth and no-investment holding pattern where the government turns the dial up or down, to ensure that differentials are reasonable, rail makes sense and production is cleared from the market. Now, our only way out is new pipeline capacity, and that has and continues to be an uncertain proposition in Canada.
In an effort to assess winners and losers, GLJ’s database has been used to understand and model the aggregate impacts of curtailment. The model parameters were applied to companies with more than 50% of their reserves in Alberta and more than 50% of their reserves in oil. Ultimately, this included 85% of the oil sands mines, 65% of the in-situ oil sands operators and more than 25 conventional corporates, overall, representing 16 of the 29 companies curtailed early in the year.
The incremental benefits of curtailment have been quantified based upon “what actually happened” versus “what might have happened.” The “what actually happened” scenario has been modeled based upon the known curtailed oil production limits through to the end of October 2019, with October production limits used as a proxy for the balance of the year, and the average actual 2019 price received, including data up to mid-August of 2019. In terms of production, this equates to 4.5% curtailment on average for 2019 relative to the pre-curtailment oil production of 3,800,000 bpd recognized by the Alberta government.
Two “what might have happened” scenarios have been modeled. The first scenario using the average actual November 2018 prices and the second scenario using the 2019 strip prices determined at November 30, 2018. In both scenarios, production is assumed as equal to the “what actually happened” scenario when modeling the 2019 impact.
Notably, the modeling indicates that the largest benefit is to in situ, with mining second and conventional operations third. In fact, all but one modeled in situ company would have experienced negative wellhead prices for 2019, in the absence of curtailment.
The chart above shows the range and volume-weighted average operating netbacks under the three scenarios and to summarize:
“What might have happened.”
- Average actual November 2018 price scenario: 40% of mining, 90% of in-situ and 20% of conventional had negative operating income
- 2019 strip price at November 30, 2018 price scenario: 40% of mining, 40% of in situ and none of the conventional companies had negative operating income
“What actually happened.”
- All companies exhibit positive operating income except for one in situ company
When the results are applied to Alberta provincial production volumes for 2019 as described above, it was estimated that curtailment added between 31 and 49 billion dollars to company revenues, 2.2 to 3.0 billion dollars to provincial royalties and 25 to 40 billion dollars to company operating income. Clearly, a tactical win and we have witnessed companies using this incremental income to pay down debt, increase dividends and undertake share buybacks.
Where do we go from here?
As of mid-October, the curtailment burden rests with 16 companies, 90% of which are weighted to in-situ and mining production. We are, however, locked into the pipeline “waiting game” with limited ability for market self-correction. Until the end of 2020, the provincial government will turn the production dial to balance differentials, rail outflows and storage.
As of July, rail had rebounded to 88% of December 2018 peak of 354,000 bpd and, currently, the Alberta government is reviewing bids in an effort to sell 120,000 bpd of rail contracts purchased in November 2018. CNRL, Suncor and Cenovus have all expressed some interest, provided they receive curtailment credits and an ability to utilize the incremental capacity.
There are also a number of near-term pipeline optimizations, which could result in over 200,000 bpd of egress added by the end of 2019 or early 2020. These include 50,000 bpd on TC Keystone, 60,000 bpd on Enbridge Express, 40,000 bpd on Enbridge Mainline and 80,000 bpd on Rangeland and, on a somewhat longer timeline, L3R will add 370,000 bpd hopefully by H2 2020.
In the medium to longer-term, the most proximal opportunity might be the reversal of the Southern Lights condensate import line at 150,000 bpd, with condensate supply for bitumen blending replaced with growth in Alberta’s liquids-rich resource plays over the next several years. Of course, we also await the go-ahead on both the Trans Mountain and Keystone Expansions adding over 1.4 million bpd of capacity for as early as late 2022.
Industry is also focused on a number of innovative technologies to ameliorate egress challenges, including partial upgrading and alternative products and shipping methods, all with the potential to save about 25% of pipeline space per bitumen barrel transported. The Alberta Innovates Bitumen Beyond Combustion initiative is particularly exciting as a means of identifying, developing and adding value through a diversified customer base (carbon fibre, vanadium, etc.) while at the same time eliminating or substantially reducing downstream emissions associated with bitumen.
A Tactic Not A Strategy
As a short-term tactic, curtailment has been a success. It is highly likely that operating netbacks would have been decimated and production would have been cut more dramatically in the absence of intervention. Similarly, corporate and government revenues are likely to have been hollowed out, leading to a drastic reduction in cash available for debt repayment and share buybacks on the corporate side and for public spending on priorities such as health care and education on the provincial side. The curtailment action protected Albertans and many companies operating here.
On the flip side, the action mitigated the incentive to grow, it played into the hands to industry detractors, and it effectively took pressure off finding the solution to Alberta’s egress problem. A problem exasperated with the August 20, 2019 extension of curtailment through to the end of 2020. To boot, the implementation of curtailment has added another notch to the belt of government unpredictability in Canada, increasing the political risk profile on investment here.
As a long-term strategy, would curtailment be considered a success? What if we are still curtailed in 2021? I will let each of you ponder and answer that question.
Since the October 18, 2019, presentation, a number of events have impacted curtailment.
The Alberta government has issued two new related Information Letters 2019-38 and 2019-42. On November 1, 2019, the government incorporated a Special Production Allowance under the Curtailment Rules wherein companies may increase their production above curtailment orders using incremental rail capacity above baseline rail capacity determined by the Minister. On December 4, 2019, the government exempted conventional wells with a spud date of November 8, 2019, or later from curtailment, opening the door for oil production growth outside of the oilsands designated areas and formations. The Alberta government has set curtailment for January 2020 at 80,000 bpd in line with December 2019.
Separately, two First Nations previously opposed to the Trans Mountain pipeline expansion have dropped their court challenges, and the Trans Mountain CEO, Ian Anderson, has indicated that “expansion project pipe” will be “in the ground before Christmas.” Some good news for the industry. Merry Christmas!
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