Tell Your Banker to Buzz Off!

As lines of bank credit grow increasingly restrictive, royalty financing offers new options for operators. This article appears in the February issue of Oilweek

By Peter McKenzie-Brown and Richard Graham

Especially if you’re a natural gas producer, it can be tough to get credit these days. What are you going to do?

One possibility is to do what Compton Petroleum did last spring. Primarily a gas producer, the company sold a 5% royalty interest in 19,000 barrels of oil equivalent (BOEs) production per day, plus a 5% interest in 600,000 undeveloped acres to Caledonian Royalty Corporation, a company founded and managed by oil and gas financier Jim Kinnear.

In a way, royalty financing is filling a gap created by the elimination of energy trusts – at least, that’s what conventional wisdom would like you to think. However, as we researched this story, it became increasingly clear that royalty financing not only meets the needs of investors (especially heavy hitters), but it is also an excellent tool to meet the industry’s needs – natural gas companies like Compton Petroleum, for example, but other companies as well. While the industry traditionally associates the idea of royalties with government take, the new players in this area are promoting it as an effective alternative financing tool. While the jury is still out on whether it will be a preferred form of funding during the next boom, right now it has a lot of merit.

The Olden Days
Royalty funding is not new in Canada’s oil and gas sector, but the industry has to a large extent lost its collective memory of royalty financing. The founder of royalty financing in Canada was R.A. (Bob) Brown who, with his son – also named Bob Brown – later turned Home Oil into a major independent oil company.

During the Great Depression royalty financing played a critical role in the development of Turner Valley – at the time “the biggest oilfield in the British Empire.” On June 16, 1936, Brown senior’s Turner Valley Royalties #1 well began flowing 850 barrels of crude oil per day. Funded by royalty financing which guaranteed investors a percentage production from successful wells, Royalties #1 found Turner Valley’s oil formation two decades after earlier producers began stripping naphtha from wet gas discoveries there. This meant the first generation of producers had wasted much of the pressure needed to produce light oil from the reservoir.

Royalties financed 69 other wells in Turner Valley in the two years following Brown’s discovery. Since only two of those wells were dry, the primary constraint on new investment was the rapid saturation of local crude oil markets.

Royalties financing didn’t last, however. In 1938 the federal government decreed that income from oil production was taxable as profits in the hands of the producing company. In the investor’s hands it was taxed again as income, rather than return of capital. Although a producing company appealed this decision successfully, the incident shook confidence in the system. Indeed, in 1942 Ottawa amended the Income Tax Act to tax oil income from royalty trusts at wartime rates. Although the federal government repealed this provision in 1950, it was 70 years before petroleum royalties again became a significant alternative to traditional debt and equity.

Teams at Play
In recent years, at least four teams have suited up for the royalty game. Each team has its own style of play and a strategy that sounds like a winner. Brickburn Asset Management has the most passive style of play. Range Royalty Management is the brainchild of Clayton Woitas, founder of Renaissance Energy, and effectively combines royalty financing with E&P. Caledonian, founded and controlled by Jim Kinnear, is new while the fourth, Freehold Royalties Ltd. has roots going back to the creation of Canada.

Until it converted to a dividend-paying corporation at the beginning of 2011, Freehold was a publicly listed trust that issued distributions based on a large number of diverse royalty-generating properties (mineral rights and gross overriding royalties) and working interest properties. Its income comes from oil, gas, liquids and potash. Many of its properties are legacy assets – royalty rights which Ottawa granted to railroads and the Hudson’s Bay Company as part of the national effort to secure Western Canada. Freehold has interests in more than two million gross acres of land and 23,000 wells.

In a statement, the company’s president and chief executive officer, Bill Ingram, said that most “of our oil and gas production comes from mineral title lands and gross overriding royalties, which have no associated capital or operating costs; thus we have relatively low capital expenditure requirements. The strength of our royalties has allowed us to preserve a high payout ratio historically and should allow us to maintain a high dividend payout.”

The newest team is that of financier Jim Kinnear, who sees royalty financing as an extension of a common practice in Canada’s mining sector. When he started out in the securities business, says Kinnear, “we invested in small mining syndicates that had acquired claims – money returned plus a carried interest. I learned about returning capital to investors. People liked to see a return of cash or cash flow, and they still do.”

Last year, after retiring from Pengrowth Energy Trust – a business he founded and managed for over 20 years – Kinnear began applying this lesson in finance to oil and gas in an innovative way. So far he and his investors have placed $100 million in Caledonian Royalty Corporation. Their royalty investments – which represent registered interests in land and rank ahead of banks and other creditors – allow qualified investors to participate in cash flow based on production. Caledonian’s royalty interests include current production and potential future production from a large undeveloped land base in Alberta. At present, those assets are heavily weighted towards natural gas.

Range Royalty Management operates rather more like a traditional oil company, but also does financing through the issuance of royalties. The company was not willing to be interviewed for this story, but a source who asked to remain anonymous describes the firm as having “a great technical team. While they always want an overriding royalty, they get at it in a different way. They begin at the grassroots level” – by going to land sales, drilling and frequently operating oil and gas properties. Issuing royalties effectively gives the company financing that bears no interest, doesn’t need to be repaid and is free of commodity price risk.

The Problem with PUDs
Another newcomer to royalty financing is Bill Bonner, president of Brickburn Asset Management. Brickburn manages four partnership funds that invest in royalty interests under the WCSB brand name.

Although he has had a long career in oil and gas financing, Bonner only added royalty financing to his company’s portfolio in 2008. His system is both conservative and traditional. “We raise capital through prospectus,” he explains, “then make that capital available to experienced operators for the completion of development wells. In return, we earn a gross overriding royalty. One way to think about this is that we rent the operator’s wellbores. We are not concerned with any of the traditional costs, including the well’s ultimate abandonment.” He adds, “The sanctity of the royalty position is a very special place to get to.”

Bonner is adamant that royalty financing in its own right is an effective and robust form of finance rather than a replacement for the energy trust. When the oil industry goes into boom mode again, “we think there will still be opportunities for this kind of instrument, although candidly we don’t know for sure.”

He adds that “the main link between us and income trusts is that we pay out capital as we receive it. We provide a stream of income which the investor really likes. We are very much a distribution model as opposed to a model where you retain capital and grow. One of the advantages we have is that our investors get a tax write-off – a 30% Canadian Development Expense, which enables them to write off all of the money they have invested. It just takes time.”

He adds, “We have completed five partnerships totalling $82 million. We only take the money for three years. At that point our prospectuses say we will offer a ‘liquidity event’ to return the capital investment back to the investor. Our game plan is to somehow monetize the property after our investments have gone through a period of flush production – either by selling it outright or by somehow putting it into a going-concern business.”

Brickburn’s first royalty partnership came about in 2008. After the 2006 Halloween Massacre imposed a new tax on energy trusts, he says “it became increasingly difficult for smaller energy businesses to finance growth because for them the liquidation opportunity (selling their assets to energy trusts) had disappeared. So we moved in with this royalty instrument.” Complicating the tax problem was the financial crisis. Traditional sources of equity and debt financing for junior oil and gas companies seemed to have disappeared. Part of the solution was royalty financing.

Brickburn royalty partnerships have participated in more than 70 wells, 95% of which used horizontal multi-frac technology. “One of the reasons operators like us,” according to Bonner, “is that we extend their budgets. If we provide one and a half million dollars for a horizontal well, it frees up that much money for them to go do something else.” Royalties can add to the companies’ bottom lines in other ways, too. One of the main reasons is that operators tend to carry inventories of “proven undeveloped reserves,” or PUDs.

“The problem with PUDs,” says Bonner, “is that you get credit on your balance sheet for them as a proven resource, but now you have to throw a lot of money at them to turn them into developed resource. What we did was to come along and offer operators the opportunity to develop those PUDs in a way that was not dilutive to equity” since royalty interest investments equate to non-repayable loans. “Even though interest rates for the last couple of years have been close to zero, royalty financing is attractive because you don’t have to pay back the principle. When operators began to see this, they quickly realized that taking our capital was very accretive to the capital they had to spend themselves.”

Through its family of funds, Brickburn has acquired royalty interests through 11 operating companies, but is bound by agreement not to mention names. However, Delphi Energy and Bellatrix Exploration have both publically acknowledged that they use royalty financing from Brickburn.

In the Centre of the Storm

This article on SEPAC chairman Stan Odut appears in the April 2009 issue of Oilweek magazine; graphic from here.

By Peter McKenzie-Brown

Toward the end of a long and thoughtful interview, a smile flickers across Stan Odut’s face. The topic of his grandchildren has come up, and he brings out a photo of the four who are aged seven and older. Wearing Ukrainian dress, they are dancing at a multi-cultural festival in Calgary. A Chinese dragon dance takes place in the margin of the picture, suggesting the great diversity of today’s Alberta. His pride is palpable and infectious, and he’s probably thinking back on a life well lived.

Odut’s story is exactly contemporaneous with that of Canada’s modern energy era. Born in Germany just as Imperial’s Leduc #1 well ushered in Alberta’s post-war conventional oil age, his family migrated to “a very poor farm” near Dauphin, Manitoba, where he grew up. The new chairman of the Small Explorer’s and Producers Association of Canada (SEPAC) moved to Calgary after earning an engineering degree from the University of Manitoba in 1969. Forty years on, no one is prouder of his city or his province than Stan Odut.

As SEPAC chair he is the voice of junior oil, and he urges small companies to join the trade association. “Membership isn’t expensive, and SEPAC can help you get your voice heard by provincial and federal politicians.” With more than 450 members, the organization describes itself as representing “Canada’s oil and gas entrepreneurs” – a tag line the association has actually trademarked.

According to Odut, the small companies need to “press for revised regulations, cutbacks in bureaucracy and a more efficient industry.” He has strong views on the changes needed to return health to the juniors.

Background: His early career included stints with Hudson’s Bay Oil and Gas, Texas Gulf and Canterra Energy – larger companies that were eventually absorbed by acquisitors. After finding himself at Husky after its 1991 takeover of Canterra, he left that corporation and began working with smaller companies.

He was one of the founders of Del Roca Energy, which eventually sold out to Tusk Energy. Five years ago he formed privately-held Sifton Energy, which he serves as president and chief executive officer. Sifton has 80 shareholders, ten employees and daily production of 950 barrels of oil equivalent. Odut’s original exit strategy was to sell out to a trust “but now with the downturn, we’re struggling a bit to keep on going. There would be no advantage in going public, though. Public companies are so badly discounted that there would be a real disadvantage to doing that.”

Now he begins to address his key messages. “The sources of capital for the junior sector are equity, debt and cash flow,” he begins. But in today’s environment, “many companies are already mired in debt and credit lines are being pulled. You can’t get additional debt coverage. You can’t raise any equity because there is no reason for investors to put money into the energy business right now. And governments (provincially in particular) have strangled cash flow. So help me with the equation: you’ve got to get one of those factors to change to get the business going again.”

Odut describes the economic situation as “dire”, and observes that it has built up over several years. The treatment of trusts has been a major contributor. Another has been the loss of the Alberta royalty tax credit. “Actions by provincial and federal government have debilitated our industry”, which is mostly headquartered in Alberta. The economic environment is becoming similar to that of the 1980s, when exploration and development collapsed, layoffs replaced hectic hiring, and Alberta’s rural areas found themselves with little work on the rigs or in oilfield construction. In both periods, the junior sector was hit particularly hard.

Just as westerners with long memories generally finger the National Energy Program as an important cause of decline in that earlier period, Odut places blame for the deteriorating situation on Alberta’s new royalty regime. “It has resulted in fewer jobs, less activity and less money in government coffers.” He acknowledges that it has been “more than the royalty regime that has killed activity…. It’s also been oil and gas prices – but those prices are the same in Saskatchewan and British Columbia” where activity is still relatively strong. In Odut’s view, Alberta’s new regime helped drive activity into the other western provinces.

“The Alberta advantage seems to have disappeared,” he laments. “You can see it in municipalities increasing taxes on infrastructure, the cost of obtaining surface leases or the new royalty system. Alberta’s bureaucracy now seems to be anti-development.” While he acknowledges that “there are land bargains out there,” he stresses that “you need cash to take advantage of them. And if I put on my Alberta resident’s hat, should I be happy that provincial (mineral rights) are being sold for a song?”

As this article goes to press, the Alberta government has promised measures that will provide relief for the juniors, and the government has agreed to consult with SEPAC and other trade associations. “My advice on help is the sooner the better,” says Odut. “We have already lost the winter drilling season. Now we have to concentrate on (getting activity going during) the summer drilling season.”

Incentives: Only two years ago, when oil prices dropped to $50 per barrel, there was no let-up in investment in Alberta. Yet last year, when average oil prices hit their all-time high, that changed. Why? Because investors no longer feel they can count on a stable regime in Alberta.

“Large companies are still going around the world and investing,” says Odut. “They know that one pass through (countries with immature petroleum basins) can give them a good short-term return. They are less concerned if the regime changes. (But Alberta) is not a one-pass-through basin. You need to know there will be a stable return over time.” After the recent changes in royalties, that certainty is no longer there.

Although Alberta is a mature basin, Odut is optimistic about its future. “Better than 35 per cent of the conventional oil resources are still there waiting to be recovered,” he says. Odut’s optimism about Alberta’s productive potential is qualified by deep skepticism about its exploratory potential. “Right now, only one (exploratory) well in seven is a decent well. I think there are still a lot of good opportunities in the conventional sector. The opportunities are in technology, because of improved recovery methods. We aren’t going to find a lot of great new fields, but we can get a lot of left-over barrels of oil using new technologies. We need incentives to do that.”

“The present regime,” he says, “penalizes you if you come up with a good well by increasing royalty rates from 35 percent max to 50 percent max”. While acknowledging that at present prices oil royalties are “at the bottom of the scale,” he stresses that the present system “penalizes horizontal wells, which reduce the industry’s environmental footprint. If you are successful, instead of having four 10-barrel-per-day wells, you could have a single horizontal well producing 100 barrels per day.” However, because the present regulations impose lower royalties on less-productive wells, “you shoot yourself in the foot by drilling (horizontally) under the existing regulations.”

At the end of last year, the Alberta government announced a 5-year window in which companies could apply the old royalty system to new wells. Stan Odut wasn’t impressed. “It doesn’t address the basic question of what you are going to drill with. You need debt, equity or cash flow to drill, and it really didn’t address any of those issues. Equity I can’t raise any, credit there isn’t any and governments are strangling cash flow.” The royalty regimes are better in BC and Saskatchewan, he says, “and BC is tweaking its system to make it even better. The biggest problem is here in Alberta.”

The outcome is that large companies have taken their cash flow and vacated the province, leaving it to the junior sector. Yet the junior companies have little to work with. To turn this around, he says, “You have to acknowledge that capital will flow to where it will get the best return. Our fiscal regime does not encourage the flow of capital into Alberta.”

What’s a government to do? Provincially, he suggests incentives for horizontal wells. Federally, he argues for changes in flow-through tax rules.

If Edmonton encouraged small companies to use horizontal wells, production would go up and the environmental footprint would go down. “You need to encourage investment in horizontal wells, as Saskatchewan does. They have a royalty holiday for horizontal wells – you pay a very small royalty on the first 100,000 barrels or so. That way the investor is able to recover his money before the government begins receiving its take.”

Ottawa, on the other hand, should take steps to expand flow-through investment. Under the present flow-through rules, companies can pass tax breaks associated with exploration directly to individual investors. The focus of that program, however, is exploration, the success of which is in decline. “Flow-through rules should (be changed to) enable companies to put flow-through money into development wells, where the risk is lower. (The federal government should) make larger sums available, so slightly larger companies could take advantage of it. This would encourage investment, and that investment would be used for drilling. Companies could choose whether they wanted to put money into exploratory drilling or development. It would give you much more cash flow.”

Peak Oil: Stan Odut is one of a growing contingent of oilmen now subscribing to the concept of peak oil – the notion that the planet’s maximum rate of oil extraction is at hand. After that point arrives, the rate of production will enter terminal decline. “I believe we probably aren’t going to see an increase on the supply side globally,” he says. “With the global economic situation there has been (crude oil) demand destruction, but I would add that there has also been supply destruction because drilling has been declining, producers are shutting in supply” and many large projects, world-wide, have gone on hold.

Prices are low because “right now oil is overbalanced on the supply side,” he says. “When things do recover, I think we are going to be in a really tight situation. The horizon might be shorter than many people predict. I think within the next five years – certainly within the next ten – we will meet a supply crunch probably like we have never seen before.”

“There’s a huge disconnect between developing world and developed world consumption,” he says. “Either we have to tap some alternative resources which we don’t really know about today, or many of us in the developed world are going to have to really cut down on our oil consumption. The developed world has to contract its consumption a lot.” This sounds ominous, and Stan Odut quickly adds that he doesn’t want to be a scare-monger.

“I’m getting a bit long in the tooth and I have an eye for what my grandchildren are going to face as we go down the road. I think they are going to be facing a different world from the one we are in today.”

Where is Alberta? Why Should You Care?

A barrel of crude oil supplies more than energy. It is also a building block for petrochemicals and other goods.

By Peter McKenzie-Brown
Can it really be true that - oil at $90 per barrel notwithstanding - the Canadian petroleum industry is facing an economic downturn? It is true, and you should care. Traditionally ignorant about Canada, Americans in particular should understand the implications of the critical economic issues now roiling the sector here. Canada is by far the largest source of imported oil for America, and one of the few large oil producers with the potential to increase production well into the future. The US Energy Information Administration has identified Canadian reserves as being second only to those of Saudi Arabia. So if you worry about peak oil and the world’s energy future, you would be foolish to ignore the geopolitics and energy economics that are racking Canada today. Canada's petroleum industry is facing a perfect storm. Five main factors are at play. First, the Canadian dollar is at its highest level against the US dollar in 30 years. Second, the natural gas industry is in the tank. Third, environmental issues are getting critical. Fourth, industrial inflation is rocketing out of sight. And finally, governments have become greedy - very greedy. Together, these developments augur ill for oil supply. Let’s look at them, one at a time.

 1. Exchange Rates: In 2001, the Canadian dollar's value was just over 60 cents per US dollar, and Fortune magazine famously dubbed our loonie the "northern peso". Today it is worth $1.04 US. During that period, oil (priced in US dollars) has tripled in value. These parallel movements have had some curious effects. Oil prices for Americans have more than tripled, based on nominal (US dollar) prices. In Canadian dollar terms, however, they have "only" doubled. That's a big increase, of course, but it's more modest than in the rest of the world. Consumers have been hit much harder in the United States than in Canada - that's on the one hand. On the other, American oil companies have benefitted far more from oil price increases than those in Canada. And since Canadian oil companies have profited much less, they have less capital for exploration and development than you might expect. Put another way, foreign exchange movements have made crude oil less profitable to develop and produce. The industry thus has less incentive to develop it.

2.The Natural Gas Sector: Forecasters now commonly suggest that western Canada's conventional gas production has peaked and will continue to decline. The reasons are complex, but part of the reality is that Canadian producers can’t sell their gas at the prices American producers command. The $7 futures contract for gas on the NYMEX is not reality in Canada. In Western Canada, our producers get $5 per thousand cubic feet for their gas, while the cost of finding and developing the stuff is in the $7-$9 range. Once again, this means less capital for investment in domestic reserves. And yet, as this article discusses below, that sector has just been hit with higher royalties. That's just what you need when new production is marginally profitable at best.

 3. The Environment: Global concern about climate change is leading to higher taxes on crude oil, most of it imposed at the retail level. In Canada, this includes transit taxes in the cities of Vancouver and Montreal, and – effective this month – a carbon tax in Québec. Retail taxes are not a concern for the oil producers, except to the extent they are inflationary. However, tough environmental rules in the upstream are creating a lot of problems. They increase costs and they delay project development. No one disagrees with the importance of good environmental regulation, but good regulation does not come cheap. It costs both time and money. Environmental regulation is adding to inflation and delaying the onset of oil production that is increasingly critical.

4. The Boom: The general boom in Alberta is also contributing to oil patch inflation. The province hosts most of Canada’s petroleum production, and is the North American jurisdiction with the lowest unemployment rate. In this province the petroleum sector faces rapidly escalating costs in almost every area. Office space in Calgary, the industry’s geographic centre, has quintupled in five years. Labour for oil sands development is astronomical. Productivity is declining. How can there be an economic boom when the basic economics of conventional oil and gas production are in decline? The main reason is that conventional reserves, which were drilled in an era of lower costs, are now getting produced and sold as quickly and profitably as possible. High prices for oil are accelerating the resource’s depletion. Costs for drilling and mineral rights have declined in the last year, but that is hardly cause for celebration. It has happened because the industry is less inclined to drill. From an all-time high of almost 25,000 wells in 2005, drilling has dropped precipitously. Estimated drilling this year will total only 17,650 wells this year and a mere 14,500 wells next. Most of the drop is in the area of natural gas drilling, but it is still something to worry about. If you don’t drill, you don’t find oil or gas.

5. Government Greed: The final piece of this puzzle is the matter of royalties and taxes. In Canada, oil and gas resources are mostly owned by government, and governments get revenue from producers in a variety of ways – primarily economic rent (royalties), sales of mineral rights, and a variety of taxes. In response to voters who are convinced high oil prices mean high profits for oil producers, Canadian governments are finding ways to increase their take from the sector.

This is their right and privilege, of course. However, the more the industry has to pay, the less oil it is going to produce. Today, things took a decidedly ugly turn for the petroleum industry in Alberta, the province that produces more than 90 per cent of Canada's oil. The province has no debt, has no sales tax and yet runs a huge fiscal surplus. This year alone the province projected the surplus to be $2.2 billion, based on lower oil price assumptions.

Its great wealth notwithstanding, this afternoon the provincial government announced a much-dreaded new royalty framework that will boost royalties by $1.4 billion per year (20 per cent) in 2010. The new rates, which will increase maximum royalties from current highs of 35 per cent to 50 per cent for conventional oil and natural gas, won't take effect until 2009. In the critical area of a regime for oil sands development, the system also changed. The current royalty is 1 per cent per year on gross revenue until a project recovers its multi-billion dollar investment. The royalty then rises to 25 per cent of revenue minus operating and other costs. Under the new regime there will be a sliding tax which starts increasing at $55 a barrel. Assuming current prices, oil sands royalties will be about 5 per cent before payout and 33 per cent thereafter. The maximum rate will be 40 per cent.


Outcome: The chart projects Canadian oil production based on the first of these two royalty regimes - the one that has so successfully encouraged development in the past. Rest assured that, under the new arrangement, future oil production from both conventional and oil sands resources will be less than the volumes projected. In a world anticipating peak oil, making oil production less profitable is a serious matter - and, by definition, the new fiscal regime will make oil and gas production less profitable in Alberta.

Love ‘em or hate ‘em, oil companies are governed by the rules of capitalism. They put their money where it will generate the best return. Canada, which has a strategically vital place in the world petroleum industry, is the world's seventh largest oil exporter, but also the seventh largest importer. In most of eastern Canada, the refining side of our industry is happily importing oil from overseas. Because they pay for it with our strong currency, it costs less. This is great for Canadian consumers.

When you have a strong currency, you have more options. Canadian producers will increasingly invest in production from riskier but lower-cost and therefore more profitable exploration provinces overseas. (One great under-explored region, for example, is Southeast Asia.) But they will do so at the expense of secure investment in Canada, including development of the vast oil sands deposits. We should worry about this, and worry a lot.