Special Report

Special Report: Will Natural Gas Save the Canadian Oil and Gas Industry? Part 1

With no resolution in sight for the high Western Canadian Select and West Texas Intermediate differentials, in addition to government policy and legislation that threaten to destroy Canada's oil and natural gas industry, coupled with low natural gas prices, many are wondering how Canada’s energy industry will survive. Yet, a credible case can be made for strong natural gas prices in the next few years.

 

This special report will start with an overview of the North American natural gas industry and conclude with reasons as to why we should be very optimistic about the not-so-distant future.

 

Part I: The Canadian Landscape

 

Natural gas used to be of greater significance to Alberta than oil, in terms of industry revenues and provincial royalty revenues.  During Premier Ralph Klein’s era, over 60 percent of provincial royalty revenues were from natural gas.

 

Significant changes in oil prices and oil sands development changed the ratio, but it was the shale gas development in the United States (U.S.) which reduced their demand for Canadian natural gas and depressed gas prices in Canada.  Development of U.S. shale plays began to takeoff in 2007, escalating further after the 2008 economic crash, fueled by a combination of near zero interest rates and vast amounts of investment capital needing to be placed.   

 

The hype of the shale revolution, both oil and gas, was countered primarily by Houston geologist Art Berman and Canadian geologist David Hughes.  Working independently of each other, they examined the production profiles of both oil and gas shale wells, capital requirements for drilling and production growth forecasts, and, after well by well and county by county examinations, they both questioned how many of these wells actually paid out.  Berman went so far as to say that if new money is being raised for a company with wells not providing the rates of return being claimed, then they fit the definition of a Ponzi Scheme. 

 

New money was being raised to stave off investment return questions by previous investors.  Primarily, it was Chesapeake Energy and Encana that paid exorbitated amounts for land in the U.S., to the point where Encana admitted that they had neither the financial or technical resources to drill on all of the U.S. shale play land holdings they had acquired, within the timeframe of the leases.  Operator claims of breakeven points which were so low they defied credibility from simply an operating cost perspective, let alone when land and capital costs were factored in.

 

There were obvious sweet spots to drill, often in small portions of some counties.  Investors were generally given the impression that shale formations are homogeneous, with all areas being equally prolific, which is far from the truth.  In his 2013 178-page report, Drill Baby Drill, and subsequent reports, David Hughes provides very detailed well and field performance analysis, which are worth reviewing. The Canadian Montney is a shale gas play with significant amounts of condensate (valuable to the oil sands producers for diluting the bitumen) that is being produced with the gas, and those wells usually achieve payout in less than a year.  Most shale gas wells are drier gas, and with normal shale wells having production decline rates of about 90 percent within 24 to 30 months, payout is usually impossible to reach.

 

Recently, the AECO (Alberta hub) 12-month natural gas price has been around CDN $2.00, while the NYMEX (USA) 12 Month Strip is currently above USD $3.00. Canadian producers are paid the AECO price, while the mainstream news media (including Calgary’s) generally reports the NYMEX price, leading to confusion about the financial health of the industry. At $2.00 per mcf, with pipeline fees and processing plant costs, producers are somewhere between a meager profit and an operating loss. Getting CDN $3.50 would obviously be gift from the gods for Alberta companies.

 

In Alberta, while the price for both oil and gas were on a strong incline, the Ed Stelmach government introduced royalty changes and changes to the formula for municipal property tax calculations for 2008.  The result was an initial 40 percent increase in the taxes oil and gas companies pay to municipal counties for each foot of gas pipeline and the value of all equipment on well sites.  While the price of gas has broad price fluctuations over the course of a year, operating costs are usually manageable enough for producers to limp along financially. In Southern Alberta, where daily gas production tends to come from shallower and lower pressured wells, the property taxes levied on oil and gas companies are the primary factor driving companies into receivership.

 

U.S. Shale Gas Plays

 

As we know, fracking is very expensive, and the wells have a high decline rates, as in 70 – 90 percent of initial production in the first three years. Each formation is different, and without actual experience, the estimated ultimate recoverable (EUR’s) touted by exploration companies and promotors are basically wishful thinking, yet billions of dollars were raised by Wall Street for promoters peddling such tales.  As the sweet spots are drilled out, lesser quality areas are drilled, and more of those need to be drilled to match the sweet spot wells.  High decline rates require constant drilling to keep up with production decline rates of older wells, let alone increasing year over year production volumes. This means additional investment dollars for increasingly lower rates of return.

 

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Over the past ten years, U.S. conventional natural gas production has declined by almost 50 percent.  By 2007, drilling in the Barnett Shale, the first tight shale gas play, had evolved such that more than 50 percent of the rapidly escalating number of gas wells being drilled were horizontal, and Barnett gas production peaked in 2012.  The Fayetteville, Eagle Ford, and Woodford formations were then explored, and now produce minor volumes, continuing their steady decline. The Haynesville was of moderate importance until Louisiana’s Sabine Pass liquefied natural gas (LNG) export terminal opened, which reduced transportation costs for Haynesville gas, making it more economically viable, and causing an upswing in production that is only a short-term reprieve from the inevitable.

 

Since 2015, drilling has been concentrated in the Permian, Utica, and Marcellus formations. The primary driver of the Permian Basin is oil along with significant amounts of natural gas, which is being shipped to Mexico by way of the rapidly developing pipeline system.  For decades, Mexico relied on burning oil from the Cantarell field, which peaked in 2004 and is now in a steep decline, making natural gas from the U.S. of great importance.  The Sabine Pass terminal is now delivering 57 percent of Mexico’s LNG.

 

Appalachia shale gas refers to production from the larger Marcellus (a Devonian formation up to 10,000’ deep) and the Utica (12,500 – 13,000’ deep) Together, they produce 48 percent of shale gas production and 31 percent of total U.S. natural gas production. Due to lower transportation costs, Marcellus gas is now being shipped to Ontario, replacing some Alberta gas. The Marcellus covers a huge area in Pennsylvania and West Virginia, with 36 percent of the gas coming from two counties, and only five counties of the state’s sixty-six counties are needed to reach 65 percent of the production.  Drilling has focused on the best areas, like all shale formation, with Washington county having the highest number of wells, and one-third of the valuable liquids production.

 

In the following chart, natural gas liquids (NGL) are shown as Oil. 

Unfortunately, the Marcellus wells are very similar to the other tight shale plays, where three-year production decline rates are about 70 – 90 percent.  Once the most attractive drilling location have been exploited, more wells will have to be drilled to get the same annual increase in production, which is on top of those new wells needed to replace production declines.  Current production is about 20 BCF/day.

 

Advocates claim:

 

  • Better technology will improve well productivity.  To date, new technology has delivered lower operating costs, in that better technology means longer wells, with each using more sand and water, and fewer wells required for the same total production, with faster drilling and completion rates at the field level.

  • Tighter well spacing will extract more gas from the same reservoir, but this has limitations, as Rystad Energy pointed out they experienced well interference in the Eagle Ford.

 

Once the Appalachia, which produces 32 percent of all U.S. natural gas, heads into a decline, and there are no other major shale plays left, what’s next?


About the Author

 

Richard Wilkie has a B. Admin and an MBA with over twenty-five years in the oil and gas industry. His experience with strategic and business planning extends to consulting projects and he is an expert speaker at conferences in Canada and the United States.


If you enjoyed this special report, please consider becoming a patron of The Visionable


Special Report: Will Natural Gas Save the Canadian Oil and Gas Industry? Part 2

With no resolution in sight for the high Western Canadian Select and West Texas Intermediate differentials, in addition to government policy and legislation that threaten to destroy Canada's oil and natural gas industry, coupled with low natural gas prices, many are wondering how Canada’s energy industry will survive. Yet, a credible case can be made for strong natural gas prices in the next few years.

 

This special report will start with an overview of the North American natural gas industry and conclude with reasons as to why we should be very optimistic about the not-so-distant future.

Part II: LNG Export Infrastructure and The Industry’s Ability to Deliver

 

In 2016, Cheniere Energy opened the first of six trains of the USD $18 billion Sabine Pass liquefied natural gas (LNG) export terminal, in an industry where 15 to 20-year take-or-pay contracts are the norm. Train number six is scheduled to open in 2019.

 

Appellation gas is now being shipped from the first of four trains from the USD $4 billion Cove Point export terminal in Maryland (0.8 BCF/day), to India under a 20-year take-or-pay contract.

 

U.S. Plans for More LNG Terminals

 

  • Six terminals of 8.1 BCF/day approved and under construction

  • Four terminals 6.8 BCF/day approved and not yet under construction

  • Twelve terminals of 21.78 BCF/day are proposed

Major capital projects require sales contracts before financing commitments are made.  While assumptions are that end users will be signing those sales contracts, 60 percent of the contracts for the U.S. terminals are with LNG traders.

 

In spite of this positive news, Art Berman continues to ask questions about the profitability of shale wells.  On September 3, 2018 Mr. Berman posted a chart showing that “88% of the sampled gas-weighted E&P companies had negative cashflow in Q2 2018.” This was a follow-up to his March 3, 2018 posting, “Shale gas is marginal at best. 79% of companies lose money (capex > cashflow from operations).

 

 

The obvious question is how long can the oil and gas industry continue to raise money when most natural gas weighted companies are losing money?  Factoring in recent strong growth in the U.S. economy means there are now more choices of business sectors to in which to investment.  Sector Rotation of Capital is the term used to describe it.  If that happens, then fewer wells will be drilled and total U.S. gas production will decline.

 

The next chart shows anticipated sources of energy and the market sectors expected to be utilizing it.  The Energy Information Administration (EIA) is forecasting renewable energy to make insignificant gains in the energy source mix. A lot of weight is riding on American producers to deliver natural gas volumes to the U.S. over the next 30 years.

 

The electricity generation sector has been trending towards natural gas, away from coal. That, along with the operational needs of industrial customer, means increased domestic consumption and less available for export contracts.

 

 On September 4, 2018, Mr. Berman pointed out that the world’s largest cargo carriers and cruise lines have ordered 125 new LNG powered ships, and that LNG bunker demand will be further increased by this previously unidentified LNG market, which could account for 13 percent of long-term demand growth.

 

EIA Forecasts

 

On November 23, 2018, Forbes reported that the U.S. could be the world’s largest exporter before 2025. On November 19, 2018, Singapore Business Review wrote, “The increasing gas demand from Asia is feared to push the global liquefied natural gas (LNG) market into a deficit in 2022-2025 as the region struggles to meet its booming energy requirements, according to an analysis by Fitch Ratings.

 

It has been eleven years since the Barnett shale gas production ramped up, and now multiple commentators are saying that all drilling has ceased and it is in terminal decline.  Seven years ago, the Marcellus began a resurgence with tight shale drilling.  With new pipelines in service, drilling and production are expected to increase, but at some point in the near future, based on the production profiles of all other shale plays, Marcellus shale gas production will begin its terminal decline.

 

In January 2017, the U.S. EIA put out its Annual Report, which was far more comprehensive than their 2018 edition:

Canadian Geologist, J. David Hughes, in his Shale Reality Check, Winter 2018, had the following observations about the EIA report:


- The EIA assumes that 96% of its estimate of a total remaining potential of 286 tcf (Proven Reserves (2015) of 72.7 tcf, plus Unproven Resources (2015) of 211.2 tcf) will be recovered by 2050.

- That is more than three times the USGS estimate., which is 84 tcf.

- To meet the Marcellus EIA forecast, 132,163 more wells will have to be drilled, 11 times more than have been drilled already, at a cost of $793 billion.

- Service company costs are rising, and where will all that frac sand and water come from, at what prices?

- Shale production is to increase by 49% by 2050.

Note the Canadian imports in light blue of the following chart:

 

This begs the question: if 96.4 percent of the estimated remaining potential is produced by 2050, what will be produced in 2051?

 

Mr. Hughes extended his calculations to determine that for the EIA estimate to come true, over one million wells would have to be drilled, at a cost of over USD $5.7 trillion just for the shale gas wells.  Once conventional and off-shore estimates are included, the numbers increase to 1.29 million wells, at an estimated cost of USD $7.7 trillion.  By this point in his report, writing that the play-level EIA forecasts are “highly to extremely optimistic, and therefore highly unlikely to be realized” seems rather obvious.

 

Throughout the entirety of this special report, possibly the most important point is that billions of dollars are being spent on LNG export terminals and ships, supply contracts are being signed, and other important and government decisions are being made based upon EIA estimates like these.

 

Take-or-pay contracts are thought of as a one-way guarantee, but the ability to take comes with the obligation to supply.  What if the U.S. oil and gas companies cannot deliver the LNG because they no longer have the enough natural gas production?

 

Our Forecast for the Canadian Oil and Gas Industry

 

  • Natural gas prices will increase by far more than Canadian industry reserve report estimates of about $3.00/mcf AECO-C in 2022.

 

  • The U.S. will need Canadian natural gas to meet their long-term needs, and this will drive prices much higher than are being forecast.

 

Within the next five years, as more U.S. LNG terminals are ready to start exporting, U.S. natural gas production will fall short of EIA estimates.  This will give Canada a big opportunity to sell its natural gas, without the barriers that have blocked the Keystone pipeline, nor a commodity price differential plaguing Canadian oil.

 

What does the Canadian oil and gas industry need to do in preparation for that opportunity?

 

  • Lobby for the reduction of Alberta property taxes to oil and gas companies and provide long-term stable funding for Alberta counties by other means.

 

  • Create a long-term strategic plan for development and production of long-life reserves of conventional natural gas.

 

  • Develop a coordinated plan to secure financial backing for this plan.  Those who financially backed the U.S. LNG terminals are those with the greatest incentive.

 

  • Canadian Association of Petroleum Producers (CAPP) should take an integrated view of the industry, one that includes greater recognition of small and medium sized producers.

 

  • Create and implement a media strategy which communicates to U.S. interests that investing E&P budgets in conventional Canadian natural gas is an excellent growth strategy.

 

Getting to this point has entailed plans with too much short-term thinking. Typical boom and bust cycles are create significant problems for all concerned and forward thinking now will make it better for everyone.

 

In Alberta, the mid-1980’s bumper sticker said, “Lord, grant me another boom, I promise not to piss it way.”  The next boom for the Canadian oil and gas industry will be supplying natural gas to the United States.  Will we see the opportunity and do what it takes to make the best of it?

 


About the Author

 

Richard Wilkie has a B. Admin and an MBA with over twenty-five years in the oil and gas industry. His experience with strategic and business planning extends to consulting projects and he is an expert speaker at conferences in Canada and the United States.


If you enjoyed this special report, please consider becoming a patron of The Visionable