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 less than CDN $1.50, while the NYMEX (USA) 12 Month Strip is currently about USD $4.50. 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 $4.50 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.
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.
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.