Introduction
Today’s article continues the series covering my recent trip to the
Athabasca oil sands around Fort McMurray, Alberta. This is an annual
trip that the Canadian government hosts for energy journalists, and
expenses for the trip were paid for by the Canadian government.
Previous articles in this series include:
- Oil Sands and the Environment – Part I
- Oil Sands and the Environment – Part II
- How Alberta’s Oil Sands are Produced
Today I want to discuss in more detail the two companies that we visited on this trip: Canadian Natural Resources Limited (NYSE: CNQ, TSE: CNQ) and Cenovus Energy (NYSE:
CVE, TSE: CVE). I will detail the cost of oil sands production via the
different methods these companies utilize, as well as the energy return
on energy invested (EROEI) of extracting the bitumen.
Canadian Natural Resources
One of the visits we made on the trip was to Canadian Natural
Resources’ (CNRL) Horizon Oil Sands Project. The project consists of
surface oil sands mining, a bitumen extraction plant, and on-site
bitumen upgrading that includes coking and hydrotreating operations. The
product is sweet synthetic crude oil (SCO), as well as diesel, naphtha,
and petroleum coke.
The process for producing bitumen via surface mining was covered in detail in last week’s article. To review, the process consists of:
- Removal of the overburden (timber and 30-40 meters of peat, clay, and sand)
- Digging up the bitumen-laden ore and transporting it to the processing facility
- Mixing the ore with hot water to separate the bitumen from the sand
- Transporting the remaining sand and residual bitumen to the tailings ponds for further settling
- Upgrading the bitumen into synthetic crude oil (this is optional, but CNRL does upgrade at Horizon)
- Ultimate reclamation of the mining site and tailings ponds
My general observations were that this is an operation of enormous
magnitude. The open pits were huge, as were the trucks to transport the
ore. The trucks did kick up quite a bit of dust as they drove past my
group at a frequent pace. Other than the dust, there wasn’t much smell
unless you stood directly downwind of the ore processing facility.
Horizon Oil Sands’ leases are north of Fort McMurray in the Athabasca
region. These leases are estimated to contain approximately 14.3
billion barrels of bitumen initially in place, with 2.9 billion barrels
of proved and probable SCO reserves. CNRL estimates that 6 billion to 8
billion barrels are ultimately recoverable. Given the scale of the
resource base, CNRL expects the mine and plant facilities to produce
for decades without the production declines normally associated with
conventional crude oil wells.
At present, the Horizon project has five expansion stages scheduled.
Phase 1 aimed to deliver 110,000 bpd of fully upgraded, light, sweet,
synthetic crude. That target was reached in Q3 2013, with a production
rate of 112,000 bpd (a 16 percent year-over-year increase).
Phases 2 and 3 plan to boost output to 250,000 barrels per day, with
potential for further expansion to 500,000 barrels per day. Production
costs at Horizon are largely fixed, so production costs on a per barrel
basis are projected to decline significantly when Phases 2 and 3 come
on-stream. Currently the cost of production is in the $40/bbl range.
Capital costs add another $10-$20/bbl, but the expected operating cost
for the life of the mine is projected to decline to between $25 and $35
per barrel of SCO. Considering that the going rate for SCO over the past
couple of years has been $90-$100/bbl, the project should be highly
profitable for the company.
While the Horizon project is a key part of CNRL’s business, the
company is involved in a number of other activities. It is the second
largest independent natural gas producer in Canada, as well as the
largest heavy oil producer in Canada. CNRL’s portfolio also includes in
situ oil sands and natural gas liquids (NGLs), and assets in North
America, the North Sea and offshore Africa.
In the most recent quarter the company produced a total of 1.2
billion cubic feet (bcf)/day of natural gas (down 2 percent
year-over-year) and 509,000 bpd of crude oil and NGLs (up 8.5 percent
YOY). Year-to-date earnings through Q3 2013 were $1.86 billion
(Canadian), versus $1.54 billion for the same time period a year ago.
Besides CNRL, other companies involved in surface mining of oil sands
include Suncor Energy (NYSE: SU, TSE: SU), Canadian Oil Sands (TSE:
COS), and Imperial Oil (NYSE: IMO, TSE: IMO). The Muskeg River mine is a
joint venture between Shell Canada (60 percent), Chevron Canada (20
percent), and Marathon Oil Canada (20 percent).
Cenovus Energy
Cenovus Energy was formed on Dec. 1, 2009 when Encana Corp. split
into two companies: the oil company Cenovus Energy and the natural gas
company Encana (NYSE: ECA, TSE: ECA). Since the split Cenovus shares
have traded mostly higher — up nearly 60 percent at one point — while
Encana shares have fallen nearly 70 percent as a result of low natural
gas prices.
Cenovus was a pioneer in the Athabasca oil sands in utilizing steam
assisted gravity drainage (SAGD). The technique has had a dramatic
impact on Canada’s oil reserves by enabling the production of oil sands
that were formerly too expensive to produce. One might say that Canada
is experiencing a “SAGD revolution” analogous to the fracking revolution
that has boosted oil production in the US. This process was also
explained in some detail in last week’s column, but consists of:
- Drilling a pair of horizontal wells, one about 5 meters above the other
- Extracting brackish ground water and converting that to steam
- Injecting steam into the upper well for months to heat up the bitumen
- Pumping the hot liquid bitumen from the lower well (steam injection continues during most of the well’s lifetime)
- Separating the returned water from the bitumen and reusing the water in the process
Cenovus is different from CNRL in that it doesn’t upgrade the bitumen
produced on site. It is typically transported to a refinery and refined
into finished products like diesel, gasoline, and jet fuel. Since
bitumen is a solid at room temperature, it has to be diluted or kept
warm to transport. Transportation can be done via a heated rail car, but
mostly the bitumen is mixed with a diluent so it flows freely, and then
transported by pipeline or rail.
Cenovus has an interest in two heavy oil refineries through a
partnership with Phillips 66 (NYSE: PSX), which enables it to upgrade
the oil to finished products. In return for the 50 percent ownership in
the refineries – Wood River, located in Illinois, and Borger, located in
Texas — ConocoPhillips (NYSE: COP) was granted a 50 percent stake in
the Cenovus projects at Christina Lake (the site I visited) and Foster
Creek.
Cenovus has been one of the most innovative companies in the heavy
oil space. Technological innovations such as injecting butane along with
steam and the company’s Wedge Well™ technology, which accesses
additional bitumen by adding a single horizontal well between a pair of
SAGD wells, have driven down costs while consuming less energy and
increasing resource recovery to a range of 60 to 70 percent.
How Wedge Well™ technology works. Source: Cenovus
Cenovus reported costs that were much lower than I expected. At the
Christina Lake site I visited, their cost of production — which factors
in taxes plus a 9 percent return — was cited at $35-$45/bbl. This is
cheaper than the overall cost to produce bitumen via surface mining at
CNRL, but Cenovus’ finished product is bitumen and not the higher value
synthetic crude oil that CNRL produces.
Cenovus cost of bitumen production. Source: Cenovus Investor Presentation
However, their costs have been declining as they climbed the learning
curve. Between 2010 and 2013 they reported that they had reduced costs
by $5-$10/bbl. But they expect that their emerging bitumen projects at
Grand Rapids and Telephone Lake will be around $20/bbl more to produce
than their currently-producing projects. Because Canadian heavy oil has
historically traded at a $30-$40/bbl discount to West Texas Intermediate
(WTI) crude due to logistical constraints, these emerging bitumen
projects may require WTI prices above $90/bbl to be economical.
According to Cenovus, there are no tax incentives available that are
specific to oil sands production. I took that to mean that there may be
industry-wide tax breaks, but they are the same for conventional oil
production and for bitumen production.
In 2012, Cenovus averaged 165,000 bpd of oil and natural gas liquids,
a 23 percent increase over 2011. The company’s strategic plan aims to
increase net crude oil production to 500,000 bpd by the end of 2021.
Natural gas production fell by 9 percent to 594 million cubic feet per
day as the company focused more on liquids production. The company’s
total proved reserves of oil, natural gas, and NGLs increased 12 percent
in 2012 to 2.2 billion barrels.
Energy Return on Energy Invested
The amount of energy required to produce bitumen has been a hot topic
for many years. Some argue that these projects are a poor way to use
energy, because the energy return on energy invested (EROEI) is ~ 3:1
(which would mean it takes 1 BTU of energy input to produce 3 BTUs of
bitumen output).
This is a simplistic picture, and only partially correct. First, as I explained in “How Not to Use EROEI“,
the EROEI of a process doesn’t necessarily say much about the economics
of the process. If you are using cheap energy inputs to produce a
higher value product, then a low EROEI might be perfectly acceptable
from an economic point of view. In the case of SAGD, they are using
cheap natural gas to produce much more valuable crude oil. Thus, in this
case a low EROEI itself says nothing about the economic viability of
the process.
What a low EROEI does indicate is that fossil fuel resources are
being depleted at a faster rate; the lower the EROEI the faster the
depletion. Thus, lower EROEI projects are generally worse from an
environmental/greenhouse gas emissions point of view.
The biggest problem with the low EROEI claims is that there is great
variation across the industry. To illustrate, consider that in any
industry, competitive analyses are often done by 3rd parties. (I have
personally been involved in such analyses). The organization doing the
evaluating will be given access to data from participating companies to
provide an overall analysis of particular metrics. They share the
results with the participating companies, but each company is only
allowed to see their rank among the other companies. In other words, in
the graphic below Cenovus knows which bars belong to them, and they know
which companies participated, but they don’t know which other bars
belong to which companies:
So we can see that in this analysis of data collected by IHS CERA, the
four lowest “steam to oil ratios” – a measure of the relative
indication of how much energy is being used — are found in four Cenovus
projects. FC, TL, CL, and NL are Foster Creek, Telephone Lake, Christina
Lake, and Narrows Lake. Their Grand Rapids (GR) project is in the
middle of the pack.
But how does a “steam to oil ratio” (SOR) translate to EROEI? I spent
a lot of time going back and forth with Cenovus on this issue. As an
engineer, a “barrel of steam” really has no absolute meaning, as it can
have differing energy content depending on the temperature and pressure
of the steam. So I asked for actual BTUs of energy to produce a barrel
of steam, so that I could make relative comparisons. After several
follow-up email exchanges and a phone call, here is what I was told by
Brett Harris, a Cenovus spokesperson:
As of the second quarter of 2012, we were using approximately 840 cubic feet of natural gas to produce 1 barrel of oil. On a BTU basis, that’s approximately 856,800 BTUs of natural gas to produce approximately 5.8 million BTUs worth of oil, which is a ratio of about 1 to 6.8.
Unfortunately, I don’t have the electricity input for 2012. The last year for which I have fully calculated numbers was 2008. In 2008, at our Christina Lake operations, electricity and diesel accounted for about 5% of the total energy input to create a barrel of oil. Natural gas accounted for the remaining 95%. At the time, our all in energy ratio to produce a barrel of oil was about 1 to 6.3. (I believe that has improved since then, but I don’t have the electricity numbers to calculate a more recent all in number for you).
So if I use the 2012 ratio of 840 cubic feet of natural gas to
produce a barrel of oil, add another 5% to account for diesel and
gasoline, I arrive at about 900,000 BTUs of energy to produce 5.8
million BTUs of oil. That results in an EROEI for Cenovus’ bitumen
production of 6.4 to 1. The EROEI has been improving over time as they
have learned what works well and what doesn’t, and it is approaching the
lower range of conventional oil production.
But note in the graphic that while the SOR for most Cenovus projects
is down in the 2 to 1 ratio (2.1 according to the graphic below), one of
their peers uses a lot more energy at ~7.8 to 1 for the SOR. While the
comparison isn’t perfect, because some companies may define a “barrel of
steam” in slightly different ways, we can make a rough estimate of the
EROEI for the industry laggards.
If we assume that 900,000 BTUs of energy inputs are approximately the
equivalent of a 2.1 to 1 SOR, then a 7.8 SOR would be approximately 3.3
million BTUs of inputs to produce 5.8 million BTUs of oil. (That may be
a slight overestimate as that also assumes that the laggards are less
efficient with electricity and diesel; if we assume that their
electricity and diesel efficiency is the same as that of Cenovus, I come
up with 3.2 million BTUs of input).
That means for the worst in class, the EROEI is only about 1.8 to 1
(5.8 million output for 3.3 million input). If these were fungible
inputs and outputs — for example, if they had to cannibalize some of
their oil to produce the energy for the process — this wouldn’t be
economically viable for that particular project. Perhaps their process
is still economical with cheap natural gas inputs and oil outputs, but
the very existence of this process means that those low-ball EROEIs
regarding oil sands production have some truth to them.
While the one company with an SOR of ~7.8 is a clear outlier, there
are a number of companies operating in the 4 to 5 range for SOR.
Assuming an average of 4.5 for the SOR and repeating the earlier
exercise, I arrive at an EROEI for these companies of 3 to 1. So it
would appear that the vast majority of oil sands operators are operating
down in the 3 to 1 range, with the very important caveat that it is
possible to have an EROEI of double that — as Cenovus has demonstrated.
How does this compare to surface mining? According to the following
graphic, Cenovus’ SAGD process is better than the average surface mining
process, which itself looks to have an SOR of about 3 to 1. That would
make the EROEI of surface mining of bitumen about 4.3 to 1 — itself
better than the average in situ process.
GHG Intensity Across Comparable Crudes. Source: Cenovus Investor Presentation
One other item of interest from that graphic is that it indicates
that Cenovus’ bitumen production actually has a better energy return
from well-to-tank than Nigerian light oil or California heavy oil. This
would take into account the production, transport, and refining of the
oil. Saudi Arabian medium crude has the lowest energy inputs on the
graphic, indicating it has the highest EROEI. (Note that in the previous
EROEI calculations, the refining step isn’t included; refining to
finished products requires another 500,000 to 600,000 BTUs of energy
input per barrel of finished product).
In next week’s article I will conclude the series on the Athabasca
oil sands by examining the logistical issues of getting the oil sands to
market, including the impact of the Keystone XL decision (regardless of
which way it goes).
http://www.energytrendsinsider.com/2013/12/09/the-cost-of-production-and-energy-return-of-oil-sands/
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