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You really know business is tough when success is measured by suffering less than others. But so it goes as the North American oilpatch enters its second year of a precipitous downturn caused by OPEC deciding to no longer support global oil prices by restraining production at its November 27, 2014 meeting. Every oil town from the Gulf of Mexico to the Northwest Territories has been negatively impacted by the collapse in oil prices and the commensurate drop in spending and drilling. Tens of thousands have lost their jobs, house prices have fallen, consumer spending in these communities has plummeted and many companies on the front line - and those which support them - have shut down or gone broke.
To describe the situation as ugly would be flattering. Unless OPEC does something most figure it won’t do (see article below) on December 4, what you see is what you get for the foreseeable future. Maybe worse.
While there is enormous background noise regarding the challenges facing the oilpatch and why the industry does what it does, when times get tough, ultimately the greatest single asset for any oil producing region of the world to prosper at a time of low oil prices is geology. It is the rocks, not the government or the scenery, that attracts exploration and production (E&P) companies to places like Iraq, Iran, Nigeria and Venezuela. It is the rocks that convince oil companies to continue investing in the face of limited pipeline access, carbon taxes, royalty reviews and growing public disdain for the oil and gas industry as a whole. Where the E&P sector is going to spend its next buck is a factor of finding and development (F&D) costs, availability of support services and market access.
Bearing in the mind the foregoing, flying below the radar of the world oil industry during this slump is the northwest Alberta community of Grande Prairie.
Not blessed with a great amount of conventional oil, the Grande Prairie area appeared on oilpatch radar in a big way in the late 1970s with natural gas and the so-called Deep Basin. In the past 35 years, Grande Prairie has turned into a major oilfield service (OFS) supply and distribution centre for all of northwest Alberta and even northeast B.C. So it was a combination of good fortune and prior investments that when the shale gas and tight oil revolution hit Canada, Grande Prairie would be sitting dead centre and right on top of a massive geological structure called the Montney. While there are many geological horizons and zone in this trend, it is clearly a spectacular reservoir with sufficient productivity to be one of the handful of places in North America were E&P companies can invest and make money at current prices.
This formation has appeared on well logs for decades but it was tight and required new technology to economically unlock the hydrocarbons. According to Wikipedia, the Montney is named after a local hamlet of the same name and was first identified in Texaco’s Buick Creek #7 well drilled in 1962, about 41 kilometers north of Fort St. John. Its general shape follows the eastern flank of the Rocky Mountain over-thrust and its characteristics vary from the northwest to southeast. However, it was the subject of a mineral rights leasing boom starting five years ago and now forms the geological underpinning of some of the most successful E&P companies able to grow production and expand in the current market environment.
Grande Prairie is almost dead centre in the geographic extent of this geological structure. The fact Grande Prairie was already a major OFS centre when the Montney leasing rush began most certainly contributed to its economic viability and meteoric growth. There are shale gas and tight oil reservoirs all over the world. The reason North America has been able to rapidly expand production from these reservoirs is the necessary OFS equipment and support services are available nearby on a standby and interruptible call-out basis. Tight oil and gas plays only work when located near significant OFS service and supply support centers. This is not the case in many other basins around the world.
Looking at recent reports for several E&P companies, it is not unreasonable to call the Montney a company maker. Rapidly growing oil companies which are still drilling aggressively despite current low oil and gas prices include Progress Energy (a unit of Malaysia’s Petronas), Tourmaline Oil Corp., Peyto Exploration and Development Corp., Seven Generations Energy Ltd. and Painted Pony Petroleum Ltd. And many others. Natural gas is supposed to be dead. But Peyto, for example, claims that in the first nine months of 2015 it has been able to put natural gas on stream for as little as $2.63 per mcf while selling it for $3.93. Tourmaline reports that in its B.C. Montney program it can develop production at $3.18 per boe, which, after operating costs of $3.50 per boe, make it quite profitable to continue drilling at current prices.
In its most recent report to investors, Seven Generations reproduced a Credit Suisse Equity Research report analyzing North America-wide natural gas breakeven prices by various plays. Of the 35 natural gas opportunities analyzed, 12 of the 16 most profitable formations (defined as adding production below breakeven prices within the recent trading range of NYMEX Henry Hub gas prices) were in some geological element of the Montney. Based on this report, the Montney was as or more profitable than the better-known Marcellus play in the northeast United States and was providing better economics than the Barnett Shale, Eagle Ford, Utica or Haynesville plays.
The active rig count tells the story. According to the JuneWarren-Nickles Rig Locator, on November 27, 79 of the 180 active rigs on that day were drilling in PSAC area AB2 which encompasses most of the Alberta section of the Montney, while 34 rigs were drilling in PSAC area BC2, which contains the rest. That’s 63 percent of the active rigs in Canada. While a good number of the rigs are south of Highway 16 (over 300 km from Grande Prairie and would therefore be serviced from another major centre like Red Deer), the majority of the drilling is in three clusters: immediately south of Grande Prairie in an area generally known as Kakwa; the Fort St. John / Dawson Creek area about 100 km west of Grande Prairie and another region about 100 km northeast of Fort St. John. While much of the support in terms of equipment and manpower for this activity will come from Fort St. John and Dawson Creek, Grande Prairie is the major OFS epicenter of all this investment. You cannot get to northeast B.C. by vehicle or truck without passing through Grande Prairie.
Of the top 10 operators on November 27 utilizing 85 rigs, eight were running the biggest iron (rated to 3,000 metres and beyond) and most were drilling in the general area of Grande Prairie. The E&P companies already mentioned in this article had 43 of these rigs running drilling wells which cost $4 million or more. When completion costs are included, these wells are the most expensive in Canada. This means the Grande Prairie area not only has a disproportionate amount of the current drilling activity in its backyard, but an even more disproportionate amount of total non-oilsands spending. Other operators running rigs in this area include global players with a multitude of alternative opportunities such as Royal Dutch Shell, Conoco Phillips and Repsol (formerly Talisman).
This is not to say Grande Prairie is an OFS paradise. It’s no fun to be in this business anywhere in the world right now. The publicly traded operators developing the Montney regularly report to their shareholders how much their well construction and completion costs have declined this year. Part of this is due to operational gains and advancing technology, but a major component is reduced drilling and service costs. As has been written by this newsletter many times before, having service and supply companies operate at little or no margin or profit is not a sustainable business model, regardless of commodity prices.
But if an OFS company or employee must be anywhere in North America during the bloodbath called 2015, it might as well be Grande Prairie. The combination of geology and world-class OFS infrastructure has combined to create what the developers claim is a profitable business at current commodity prices. If only prolific geology allowed a bit more of this prosperity to be spread around Western Canada.
The Paris climate change conference (PCCC) began November 30 with Canada having a large presence. Important to Alberta Premier Rachel Notley was ensuring her carbon tax strategy was released on November 22 prior to the conference and meeting on this same subject with her federal and provincial counterparts. There has been considerable discussion and analysis since then, ranging from unquestioned support to unbridled opposition. The final report and outcome of the PCCC won’t be known until December 11. However, several comments in the Canadian media are noteworthy.
Deborah Yedlin, a business columnist for the Calgary Herald, wrote approvingly of the policy the very next day. She called Notley’s policy “a day of vindication” for Suncor CEO Steve Williams, who has been advocating for carbon tax for some time. Yedlin was somewhat more reserved a few days later after receiving and analysing the feedback from other parties affected by the policy change. Regardless, she concluded her initial analysis on November 23 with the following words; “Alberta has taken a needed bold step forward.”
In Lake Louise at an oil investment conference a few days later, Canadian Natural Resources Limited (CNRL) founder and boss Murray Edwards spoke optimistically about how this policy could change the debate about oilsands development and new export pipelines. Edwards went as far as to say he would like to see people advocating for “clean oil” from Alberta, now that the province has taken such an aggressive position in taxing all forms of carbon-based energy. Talking to reporters Edwards said, “I hope that the leadership position helps change the conversation in Canada, that we are what I would call ‘clean oil’, and provide leadership on a global basis. My view is that the industry is doing the right thing as a responsible developer and we think it is important to communicate, to reflect Canadians’ aspirations and value set.”
Some people believe Alberta’s carbon tax moves will help move the needle on changing the world’s climate, defined as less warming, fewer violent storms and weather events, slower melting of glaciers, lower ocean levels, fewer droughts and less disruption of people because of the weather. Media reports from Paris this week actually linked climate change to terrorism. One letter writer to the Calgary Herald wrote about the estimated cost to Albertans, saying, “$470 per household annually by 2018. That’s less than $1.30 per day (the cost of a cup of coffee in many places). If the household can’t afford that in the interest of a better climate, it’s a sad state of affairs.”
Many folks in the developed world would be happy to save the world at only $1.30 per day. The question is if Alberta’s new carbon taxes alone will actually cause this to happen. Whether or not Alberta’s new carbon taxes will make building pipelines easier is not known. Even Edwards admitted in Lake Louise it was hard to predict if environmentalists would drop their vociferous opposition to new pipelines to carry oilsands production to tidewater and export markets.
However, the battle against carbon emissions and energy development is nowhere near over, nor is it confined to the oilsands and hydrocarbon fuels. The Globe and Mail carried a story November 27 which revealed environmentalists in New Hampshire are opposed to a new electricity transmission line to carry hydroelectric power from Québec through that state and on to consumers in Massachusetts and Connecticut. The Sierra Club claims branding Québec hydropower as “clean” is in fact greenwashing, the term coined to describe something is environmentally friendly when it is not.
Opponents in New Hampshire are calling Québec’s hydroelectric power “dirty” because of the carbon released (or not captured) when large sections of boreal forest are flooded to create reservoirs. This has put Hydro-Québec on the defensive, forcing the utility to explain how over the next 100 years, the greenhouse gas generated from hydro in the hinterland of northern Québec is comparable to wind power and at a substantially lower cost than solar panels, which will have to be replaced several times over the next century.
It is ironic to see Quebec on the defensive for producing hydroelectric power after all the advice that province has dispensed to Alberta.
Alberta’s policy process was rushed. Many details were lacking, the most important being costs for major initiatives such as eliminating coal-fired electricity generation, reducing methane gas emissions and the impact on electricity bills of moving from cheap coal to more expensive renewables.
In an interview with the Globe and Mail on November 27, climate change panel chair and University of Alberta academic Andrew Leach said “We put a lot of emphasis on pulling in massive amounts of information, and our timelines, as they got accelerated, particularly by the first ministers meeting, I don’t think we had quite enough time to digest every little bit of information that came to us. We didn’t have time to drill down with as many of the stakeholders that provided valuable input to us. The variety of information that came in and our ability to absorb and use every bit of it was pretty limited in some cases.”
Lastly, on December 2 The Financial Post reported a “secret deal” was negotiated among the four big oilsands producers which appeared at the announcement with Premier Notley – CNRL, Suncor, Shell and Cenovus – and several environmental groups. Apparently these companies agreed to a carbon emission cap on oilsands production in exchange for these groups dropping their opposition to export pipelines. This has caused significant rifts among these four companies and other oil and gas producers. Claudia Cattaneo, western business reporter, wrote, “… leaders of competing companies, including Imperial Oil Limited chairman and CEO Rich Kruger and MEG Energy Corp. Pres. and CEO Bill McCaffrey, were not consulted and are reportedly outraged by the secret deal. The arrangement details and backers, other than the Pembina Institute, remain unknown, said senior industry sources.” She finished the article writing, “Tempers flared when the four oilsands leaders briefed CAPP (Canadian Association of Petroleum Producers) members last week.”
The problem of course is if there is a ceiling on oilsands emissions, which company’s projects will be deemed acceptable and which will not?
It has been a year since OPEC made the decision to abandon its historic role in global crude supply management and “let the market decide.” Millions of words have been written speculating why Saudi Arabia – the world’s only true swing producer – made the decision to trade volume for price. No one knows for sure what will happen at this year’s meeting, thus the outcome of the pending OPEC chinwag remains unknown.
Obviously, the Saudis will be making a statement of some sort to the assembled members and delegates. Here are the highlights on what Saudi Arabia – and to a lesser degree its colleagues in the Persian Gulf – have accomplished in the past year.
So when the Saudis address OPEC, it will be interesting to hear what words they choose to describe what has happened the world oil industry in the past year as successful. This situation is simply not sustainable.
Alberta has about 70,000 suspended oil and gas wells. For a variety of reasons, they have been deemed uneconomic to produce and are therefore not on stream. For years, OFS has looked at the enormous backlog of wells which are suspended or requiring abandonment and figured there was money to be made on one last visit to that location. But as the inventory of wells suspended or awaiting abandonment has continue to grow, the reality is the economic opportunity for OFS has been disappointing at best.
Producers continue to kick the well abandonment can down the road. Given the industry’s current cash crunch, abandonments are not a high priority. Other factors include the ability of mineral title holders to push well abandonment into the future by maintaining mineral title payments, and the regulatory issues surrounding abandonments (which leaves total costs ultimately unknown in the worst cases),
Two media stories highlight the nature of the problem. On November 26, the Calgary Herald reported Spyglass Resources Corp. had been placed into receivership by its secured lender. The question emerged whether the well abandonment liabilities were now the responsibility of the lender or the province. If the bank takes ownership of the assets, this also includes the mineral leases. As the holder, the lender might technically also assume ownership of the abandonment obligations. The newspaper reported the Alberta Energy Regulator (AER) had placed this issue in front of the courts resulting from the insolvency of Redwater Energy Corp. which was placed into receivership in May. Apparently, when Spyglass was placed into receivership, the AER asked courts to compel the receiver to comply with well abandonment orders issued by the regulator using funds from the estate.
Meanwhile, in another media report in the Daily Oil Bulletin the next day, the issue of whether it was realistic for the AER to force producers with no cash to honor their well abandonment obligations was analyzed. Two years ago, the AER introduced changes to its licensee liability rating (LLR) rating system to ensure well operators had sufficient funds to cover future well abandonment obligations. This caused many small gas producers heartburn because the new rules required struggling companies to put more cash on deposit with the regulator, at the same time they were struggling to keep the lights on.
After oil prices joined gas prices in the dumpster, some juniors apparently were keeping wells on stream at a cash loss because it cost less to lose money operating wells than top off their LLR accounts. Bruce Edgelow, vice president of energy lending at ATB Financial, told an investment executive luncheon the tougher regulatory rules were forcing some producers to make the wrong decision. He said it was not a matter of insolvency but cash management. It was cheaper to produce the wells at a loss than shut them in and have their LLR and subsequent abandonment cash reserve allocations recalculated.
The entire suspended and abandoned well situation in Alberta remains an enormous opportunity for OFS without the capital to exploit it. Every well to be abandoned needs a service rig, wireline work, cement, lease cleanup, the environmental engineering and testing, trucking and a lot of labor. If every suspended well in Alberta were abandoned at a cost of $300,000 (which is probably low), it would require the expenditure of $21 billion, more than half the average capital expenditures the conventional side of the Canadian oilpatch has invested in the past decade.
It is clear producers don’t have the cash and the regulators have not figured out how to make it happen.
The above headline of course means it is going to blow up in the not-too-distant future. A November 29 article on the website energyintel.com said, “The U.S. E&P sector could be on the cusp of massive defaults and bankruptcies so staggering they pose a threat to the U.S. economy… How bad could things get and when? It increasingly looks like a number of the weakest companies will run out of financial stamina in the first half of next year, and with every dollar of income going to service debt at many heavily levered independents, there are waves of others that also face serious trouble if the lower-for-longer oil price scenario extends further.”
The problem is the way many players in the U.S. light tight oil (LTO) boom were financed. In an era of very low interest rates – commonly called quantitative easing – drillers raised money using high yield debt. For many, investors the coupon on the junk bonds was as or more important than the borrower’s capacity to repay. Many analysts have written one of the reasons American LTO production has remained so high is leveraged producers are slaves to their lending obligations, so they keep pumping oil even if it does not generate sufficient free cash to cover production replacement costs.
Many producers have been sheltered by future production hedges for the past year. But as these hedges expire, they cannot be replaced by futures contracts at anywhere near 2014 prices. The article detailed how 153 E&P companies covered by credit agency Standard & Poor (S&P) had negative free cash flow of US$24 billion so far in 2015. Reductions in capital expenditures and efficiency gains will assist these companies in generating a positive cash flow of US$8 billion in 2016. But of course, this can only occur if the companies don’t drill, which means they’re going out of business. The underlying asset base of the debt securities will continue erode, exacerbating the problem.
What does this mean for Canada’s OFS sector? U.S. LTO production will continue to decline significantly, meaning global supply and demand will slowly march towards equilibrium sometime next year. For OFS operators with U.S. operations, this means unless oil prices rise sharply, an increase in American spending and drilling appears unlikely.
Drilling activity in Canada, North Dakota and rigs targeting oil in the U.S. appears to be stabilizing. Stabilizing is defined as not declining at previous rates. The fact the Canadian rig count has not moved on a week-over- week basis is troubling because this is the time of year when field activity historically increases. U.S. oil rig drilling activity is at levels not seen since June 2010, and activity in North Dakota is down about two thirds from levels over the past four years.
Source: Baker-Hughes Rotary Rig Count November 13, 2015
Source: North Dakota Department of Mines & Resources
David YagerNational Leader, Oilfield ServicesDirect 403.648.4188Cellular 403.461.8566
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