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Call it the new era of reverse negatives. It’s not that the Alberta government did something good as much as it didn’t do something bad. The NDP’s long-awaited royalty review was released January 29 and depending upon where the final royalty curves end up (the future royalty rates for oil, natural gas and natural gas liquids were not released and have yet to be determined), the outcome for the oilfield services sector (OFS) could be neutral to positive. Again, it’s not so much this is good news. It was already announced the royalty regime would not change in 2016. Nor is it bad news which, in this market, is positive
The oil industry and the investors who support it had every reason to be nervous. In the 2015 election campaign, aspiring premier Rachel Notley’s platform contained the following confidence-shattering nuggets; “The PCs have…refused to implement realistic oil royalties that the people who own the resources – all of us – deserve. The reason for this refusal is clear: Jim Prentice and the PCs are too close, much too close, to a small minority of Albertans who benefit from the status quo under the PCs, while the people of Alberta as a whole are deprived of much of the benefit of our own resources.“ That hundreds of thousands of Albertans directly and indirectly benefit from internationally competitive royalties was either not understood or not sufficiently attractive to the NDP voter base.
After election, the NDP moved quickly to raise corporate taxes, large emitter carbon taxes, income taxes on high earners, minimum wages and unveiled a $3 billion-per-year carbon tax program, all the while calling Alberta the “embarrassing cousin” of Confederation. Industry managers, workers and investors can be forgiven for being apprehensive about what the NDP had planned for royalties. The review panel included business leaders but so did the much-reviled 2007 process. That didn’t change the outcome in 2007.
However, the dismal state of oil prices, Alberta’s economy and changing world oil markets most certainly created an undeniable economic case that it was impossible to expect Alberta’s battered oilpatch to contribute even more revenue to the province. The title of the 209-page report on the Energy Alberta website read, “Alberta at a Crossroads.” The opening line of the executive summary goes, “The future of Alberta’s energy industry is not going to be like the past… Our panel found that, overall, Alberta’s royalties are comparable with other jurisdictions.”
Therefore, the focus was on transparency and modernizing the regime as opposed to collecting more money. As Premier Notley said when the package was announced, “It is not the time to reach out and make a big money grab, because that is not going to help Albertans.” The fact the largest historical customer for Alberta’s oil and gas – the United States – is now a major competitor was not lost on the reviewing panel nor the government.
Historically, OFS has been roadkill when it came to governments deciding on appropriate economic rent from oil and gas production. When PC leader Peter Lougheed became premier in 1971, he set a new target royalty of 19% to 23% after the “marginal” (maximum) rate had been 16 2/3% for the previous decade. When oil prices started rising in 1973 and a battle for wellhead production windfalls between Ottawa and Edmonton began, the result was a process which saw Alberta’s marginal royalty rate rise beyond 50%. Fortunately, oil prices were rising enough that governments were able to have an epic federal / provincial battle culminating in the National Energy Program (NEP) in 1980 without materially impairing capital spending and drilling activity. It was only after the NEP was introduced OFS realized it had to get on the public policy map when big oil and big governments fought over oil money.
The downturn in the 1980s has largely been blamed on low oil prices. What is seldom discussed is Alberta’s higher royalty rates (three to four times higher than they were in the 1950s and 1960s) remained in place, offset periodically by royalty deductions in the form of drilling incentives to keep OFS alive. By 1991, the Alberta government realized its royalty regime was not competitive and introduced a major reduction which was the foundation of many years of growth and prosperity. This lasted until the PC leadership race to replace then Premier Ralph Klein in 2006 when royalties again became a public policy issue.
The New Royalty Framework introduced in 2007 was widely regarded as a disaster because it raised royalties significantly. Then oil prices began falling within a year and collapsed by late 2008 making the new policy worse. In 2010, the government undertook a competitiveness review and reduced royalties, plus added incentives in the form of reduced front-end royalties for horizontal drilling. This system will remain in place until the so-called Modern Royalty Framework recommended by the review panel takes effect January 1, 2017. The current regime has been grandfathered for 10 years for wells drilled through to the end of 2016.
In the past, royalties have been increased during times of rising or high oil prices and aggressive capital spending. This has disguised the impact on OFS. Since that time, OFS trade associations have been active in explaining the size and depth of the upstream oil and gas supply chain and how taking more cash out of the system at the wellhead through higher royalties negatively affects OFS. People are finally listening. Governments and producers have for several years been trumpeting the importance of this supply chain nationally as a justification for continued oilsands development.
The oilsands royalty regime is considered to be acceptable in its current form. The report’s authors do not foresee any major investments in greenfield oilsands mines in the near future, a factor of low commodity prices, high development costs, a lack of lower-cost pipeline access to tidewater and competitive investments with faster payouts in light tight oil and shale gas.
The regime for conventional drilling for light tight oil and shale gas will change – probably for the better – depending on where the royalty curves are finally set. Presently on horizontal wells a 5% royalty is levied on the first 30,000 to 50,000 barrels produced or a certain time has transpired varying for wellbore depth and length. When prices were higher, a good well could pay out under this regime before a higher royalty rate was charged. However, at current prices this formula is acting as a disincentive. With oil prices down 60% few if any prospects can achieve invested capital payout based on barrels produced at the 5% rate, even with greatly reduced service prices.
Starting January 1 next year, the 5% royalty rate will be paid until the capital cost of drilling and completion is recovered. This will be based on a well cost schedule for various prospects in different parts of Alberta’s basin. This formula is similar to that employed in the oilsands and many other regimes around the world where the government leases mineral rights. The report also recommended a specialized program for enhanced oil recovery from existing wells in fields and for experimental wells that may lead to recovery from different producing horizons or technological improvements which can be employed industry-wide.
While this should make the economics work for more prospects, it is in the Alberta government’s best interests to reduce drilling and completion costs, which will accelerate payout resulting in higher royalties. This caused the Canadian Association of Oilwell Drilling Contractors (CAODC) to comment; “CAODC is concerned about the Alberta government’s objective to incentivize oil and gas producers to reduce costs through the Drilling and Completion Cost Allowance” at the same time Edmonton is driving up costs through higher fuel taxes, increased corporate taxes, carbon levies and a higher minimum wage. The CAODC also noted the report says the royalty regimes are more attractive in Saskatchewan and British Columbia than Alberta. The panel and government ignored the CAODC’s request to reduce royalties to encourage drilling and offset higher provincial tax rates.
Although the general response by industry and media has been positive, there is a critical element missing; the post-2016 royalty curves. Canadian Association of Petroleum Producers (CAPP) president Tim McMillan told the media, “The numbers weren’t laid out today, and those are going to matter.” Apparently this information will be released by March 31, 2016.
So, before OFS breaks out the no-brand beer (nobody can afford champagne this year) and toasts to better days ahead, the shape of the as-yet unknown royalty curves are extremely important.
The graphic above is from the Energy Alberta website. These are the “royalty curves” which are sensitive to volume and prices. The top graph shows the marginal royalty rate at 40%. Introduced in 2010, this replaced the 2009 royalty curves introduced in the New Royalty Framework of 2007 which raised the marginal royalty rate to 50% on January 1, 2009 (lower chart).
That Alberta’s royalties on conventional production (light tight oil and shale gas are still classified as conventional) are sensitive to both price and volume works well for developers and the Crown. When things are going well, the Crown prospers. When prices and individual well productivity decline, the royalty system acts as an incentive to keep wells on stream.
The general reaction to the royalty review has been positive, conditional, of course, on the final royalty curves and rates. It is remarkable how much positive press the program received considering one of the most important elements of the long-term rate of return on investment was missing. Many who speculated on the outcome of the review felt the status quo would prevail when prices were low, but if prices spiked again, the marginal rate would be higher than it is now. This may still be the case.
Dissent over the royalty review within the NDP’s historic support base has already begun. Alberta Federation of Labor president Gil McGowan and federal NDP candidate in the last federal election has already publicly criticized Premier Notley when he told the Edmonton Journal February 1, “We think the government got it wrong on royalties.” While McGowan said he accepts not charging higher royalties when prices are very low, he wants higher royalties with higher oil prices. “Specifically we argued that one of the big problems with Alberta’s current royalty system is that it has failed to collect a reasonable share for the public at high prices”.
Again, nobody should call this file closed until the final royalty curves are revealed.
In the meantime, for OFS this could be one less problem to deal with during extremely difficult business conditions. If the royalty curves don’t end up too onerous, perhaps this will be a signal to domestic and international investors Alberta’s NDP government will listen to markets and industry as it moves forward.
On February 1 the Alberta government announced a $500 million royalty credit incentive program to spur the construction of more petrochemical processing plants in the province. The government figures this could result in the investment of $3 billion to $5 billion in new facilities creating 3,000 jobs during the construction phase and 1,000 job in long-term employment. The idea is to continue to turn raw material like methane, ethane and propane in value-added products like plastic and fertilizer. Alberta has vast reserves of these products which are currently priced at very low levels and facing intense competition from new supplies in the U.S. like the Marcellus Shale in Pennsylvania.
This is a positive development for OFS which does good business building oil and gas production and processing facilities.
Hydrocarbon production and international sale of crude oil, natural gas and natural gas liquids was Canada’s number one export in 2014. The following numbers appeared on a website called World’s Top Exports (WTEx). The dollar value is followed by the percentage of total exports by each commodity or product
Oil alone was greater, percentage-wise, than the bottom eight combined.
When times get tough at home, many OFS managers dream of greener grass in other oil-producing jurisdictions. Many of these have lower finding and development costs and are desperate for new equipment and technology and top-notch service, something the Canadian OFS’s is famous for all over the world.
But as many have learned over the years other countries carry elements of risk that do not exist in Canada. Besides physical risks such as kidnapping, bad roads, worker safety issues, terrible drivers or substandard transportation systems, graft, kickbacks and other financial and commercial risks are not uncommon. Everybody who has worked abroad for any period of time has a story of some sort on how different doing business is in various parts of the world. Very few are complementary. The main attractions is the money and occasionally the weather.
Every year an organization called Transparency International compiles and publishes a global public sector corruption index. In it, 154 countries are listed in order of honesty and transparency from top to bottom. Every worker or company operating in a foreign land has to deal with the government at some level, starting with entry into the country (and getting out again), to importing equipment or establishing a business operation. The global oil industry has figured out how to work almost everywhere using methods no one is particularly proud of and some of which would be considered illegal in many jurisdictions.
Transparency International notes many of the countries with the lowest scores – Somalia, Sudan, Afghanistan, North Korea and Somalia – are characterized by oppressive dictatorships and / or entrenched and bloody domestic conflict. These countries ranked 163 to 167 and were not scored.
In ranking the countries, a score of 100 is classified as “very clean” while zero would be “highly corrupt.” Of the significant oil and gas producers in the world, Canada ranks number three at 83 and ninth overall behind Demark (1 at 91), Finland, Sweden, New Zealand, Netherlands, Norway Switzerland and Singapore (8 at 85).
United Arab Emirates
Trinidad and Tobago
Caterpillar Inc., the world’s largest manufacturer of so-called “yellow iron” used to move dirt and build roads, has downgraded its 2016 sales forecasts. This is as a result of a global drop in commodity prices and significantly reduced spending on mining, oil and gas development and related resource infrastructure construction.
The company’s sales were US$55.2 billion in 2014 but this fell to US$47 billion in 2015. The company is offering guidance between US$40 and US$44 billion in 2016. Caterpillar said by 2018 it will have restructured significantly, resulting in the elimination of up to 10,000 jobs. The company estimated its 2015 restructuring costs at US$908 million, with another US$400 million set aside for retooling in 2016.
Significant U.S. independent oil and gas producer Murphy Oil Corp. still sees opportunities in Canada. The Globe and Mail reported January 27 Murphy had sold two natural gas plants in northeast B.C. to Enbridge Inc. for $538 million. Murphy also announced it would be investing $250 million with Athabasca Oil Corp. to develop that company’s Kabob / Duvernay and Montney properties in northwest Alberta. Murphy will learn a 70% working interest in the Kabob / Duvernay assets and a 30% working interest in the Montney properties by agreeing to pay $225 million worth of Athabasca’s development expenses over the next five years. Athabasca had been seeking a partner to develop its Duvernay properties for over a year.
Perhaps US$26.68 a barrel for WTI on Wednesday, January 20 was the basement. On February 1 Bloomberg Business reported for the weekly reporting period ended January 26 futures traders, also called speculators, told the U.S. Commodity Futures Trading Commission they had increased bullish bets on future oil prices by the largest amount since 2010. Some analysts called it short-covering, while other are thought to be trading on rumors of a possible production cut by Saudi Arabia and Russia. So called “longs” increased positions by about 35% while short positions declined by about 2%. January closed the month at US$33.62 a barrel for WTI, 26% higher than the lowest closing price on January 20, which was also the lowest closing price for WTI since the spring of 2003.
The peak of the Canadian winter drilling season seems to have come and gone as the February 2 active rig count of 218 is the lowest in the past three weeks. The only weekly report lower was January 5 when rigs were just getting fired up after the holiday season.
North Dakota drilling is suffering mightily under collapsed oil prices. On a percentage decline basis this market is suffering the worst on a year-over-year basis of the three drilling activity metrics under review.
Oil drilling in the U.S. continues to decline with the Baker Hughes land rotary rig count showing declines for six weeks in a row. Except for one bump in mid-December, this metric of the health of U.S. oil producers has been in steady decline since activity peaked in October of 2014.
Source: Baker-Hughes Rotary Rig Count January 29, 2016
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