Even the Best and Brightest Minds Can Get Things Wrong
In the summer of 2002, the National Petroleum Council (NPC) gathered together some of the smartest minds from the oil and gas industry, academia and in the environmental community to study the potential for natural gas in North America. The study lasted for the better part of a year, after which a report titled “Balancing Natural Gas Policy – Fueling the Demands of a Growing Economy” was released.
As we sit here 16 years later, reviewing the findings of this study in light of the current situation where natural gas in North America and globally is concerned is a fascinating exercise — one that demonstrates the challenges presented to even the most informed and intelligent people when it comes to making accurate projections about how the oil and gas industry will evolve in years to come.
I personally chaired one of several subcommittees that were established to conduct various aspects of this study, led by ExxonMobil and Burlington Resources, which was my employer at the time. When the study was issued, those of us who had worked on it were quite proud of it and were firm in our belief that it would stand the test of time, providing an accurate roadmap for the public and policymakers to use as a guidepost for years to come.
Providing such guidance is, after all, the role of the NPC, a federal advisory committee that reports directly to the U.S. Secretary of Energy. The NPC’s own website describes its role, in part, as follows:
The National Petroleum Council (NPC), a federally chartered and privately funded advisory committee, was established by the Secretary of the Interior in 1946 at the request of President Harry S Truman. In 1977, the U.S. Department of Energy was established and the NPC’s functions were transferred to the new Department. The purpose of the NPC is solely to advise, inform, and make recommendations to the Secretary of Energy with respect to any matter relating to oil and natural gas or to the oil and gas industries submitted to it or approved by the Secretary. The NPC does not concern itself with trade practices, nor does it engage in any of the usual trade association activities.
Even though the NPC had conducted a natural gas-related study in 1999, incoming Bush Administration Energy Secretary Spencer Abraham felt that the situation had shifted significantly enough by 2002 to warrant another look. It is important to keep in mind that, when the request came down from Secretary Abraham, natural gas was a commodity in short supply and subject to huge price swings. Because a large percentage of our country’s production came out of the Gulf of Mexico, it was also subject to being significantly interrupted by major hurricane events.
In 2002, the Barnett Shale was the only major natural gas-bearing shale formation that had been discovered. The Barnett was in the early stages of its development, and the industry had little understanding of its ultimate potential. Nor did any of the experts assembled by the NPC for its new study have any inkling of the magnitude of domestic natural gas resource that would be discovered in massive reserves trapped inside formations with names like Marcellus, Haynesville, Bakken, Eagle Ford, Spraberry, Woodford and Wolfcamp.
One of the most popular bits of conventional wisdom said about any economic study is “garbage in, garbage out.” Our base of information for the 2002 NPC study wasn’t “garbage” — the information we had was high-quality, but it was also very limited. The study by its very nature had to be based on available data, and the data available at the time indicated that North American natural gas production through the year 2025 would be characterized by limited domestic output, rising imports of liquefied natural gas (LNG) coming into the country on huge tanker ships, and high commodity prices as a result.
It should come as no surprise that the study’s findings, some of which we will review here as examples, reflected this general outlook.
Every study based on economic analyses will include multiple cases that produce differing outcomes. Typically, these are described as a “base case” which assumes a status quo of outside-influencing factors going forward, an aggressive case that assumes some set of positive changes, and possibly even a non-aggressive case that assumes a set of negative changes.
One of the big decisions the NPC study committee had to make revolved around how many cases to include and how to structure them. In the end, the decision was made to include:
• “Balanced Future” case in which U.S. energy policy would evolve in ways that would encourage the development of new natural gas resources and the building-out of adequate midstream infrastructure and LNG import facilities; and
• “Reactive Path” case in which energy policy evolves, but mainly in reaction to various negative events such as shortages of supply or crises caused by lack of adequate infrastructure.
Given that background and knowledge about how the study was structured, the fact that most of the findings produced in our report have turned out be quite inaccurate should come as no surprise. Here are a few of them taken from the study’s Executive Summary:
• From page 32-33: “Given the relatively low production rates from non-conventional wells, the analysis further suggests that even in a robust future price environment, industry will be challenged to maintain overall production at its current level. This conclusion is reached even though new discoveries in mature North American basins represent the largest contribution to future supplies of any component of this supply outlook.”
• From page 33: “The NPC estimates that production from the lower 48 states and non-Arctic Canada can meet 75 percent of U.S. demand through 2025. However, these indigenous supplies will be unable to meet the projected natural gas demand.”
• From page 52: Price Projections: The NPC “Balanced Future” case projected a 2019 average price of between $3.20 and $5.00 per mmbtu. Its “Reactive Path” case projected a price range of $5.00 to about $6.90.
• From page 63: “To meet future demand, the NPC is projecting LNG imports will grow to become 14-17 percent of the U.S. natural gas supply by 2025. This will require the construction of seven to nine new regasification terminals and expansions of three of the four existing terminals.”
Of course, with the benefit of 16 years of hindsight, we now know that none of these key projections have come to fruition. For example, where prices are concerned, today’s natural gas producers can only long for a price per mmbtu of even $3.20, much less long-forgotten levels of $5.00 or $6.90.
Far from being challenged to maintain overall current production levels, today’s natural gas industry struggles with finding adequate areas of demand to which to move their product, even as the number of active drillings exploring for natural gas resources has fallen from 1,600 as recently as 2012 to around 130 at the first of 2019. In a way, producers are victims of their own expertise. Having become too adept at maximizing volumes from each new well, that threaten to oversupply the market―even with a dramatically-reduced rig count.
The nature of the shale plays discovered since 2003 has also played a large role in creating this new reality for gas producers. It’s not just the massive resource containe in natural gas plays like the Haynesville and Marcellus keeping the gas rig count low — it’s also the amazing volumes of methane flowing out of what are classified as oil wells being drilled in the Bakken, Eagle Ford and the Permian Basin. A little-recognized fact of life in today’s U.S. oil patch is that the oil-heavy Permian Basin is now the second-largest producer of natural gas in North America, behind only the Marcellus/Utica Basin.
Simply put: Today’s biggest problem for natural gas producers is not a lack of supply, but lack of demand.
It’s important to recognize that this sea-change in the supply/demand equation for domestic natural gas has taken place during a period of time when demand for natural gas has increased significantly. In 2003, Americans and American businesses consumed about 22.7 trillion cubic feet (tcf) of natural gas, according to the U.S. Energy Information Administration (EIA). By 2017, overall U.S. consumption had grown to 27.1 tcf, an increase of 20 percent.
More to the point, demand for natural gas over that period of time rose in all of its key demand sectors: It was up in power generation, up in home heating use, up in chemicals and plastics and all other key manufacturing uses. Indeed, the phenomenal new abundance of natural gas supply and the chronic low prices that abundance has produced has played a significant role in the ongoing renaissance of manufacturing in the U.S., making the country globally competitive in that space for the first time in several decades.
This newly-found abundance may be a curse to natural gas producers and their bottom lines, but it has been a true blessing to the country.
The Short-Lived Race to Import LNG
All of that brings us to that fourth and final finding listed above:
“To meet future demand, the NPC is projecting LNG imports will grow to become 14-17 percent of the U.S. natural gas supply by 2025. This will require the construction of seven to nine new regasification terminals and expansions of three of the four existing terminals.”
That one didn’t work out at all, although the issuance of the NPC report in 2003 created an initial flurry of new investments in new LNG regasification terminals in the U.S. and other projects designed to get major companies in the game of importing LNG into this country.
ExxonMobil is a great example. The company had already been involved in the LNG business for decades prior to its leadership of the NPC study effort, and moved quickly to expand its involvement in the sector following the issuance of the report. Through a partnership with Qatar Petroleum, ExxonMobil developed two new classes of larger, more fuel-efficient LNG tankers by 2009―the Q-Flex and Q-Max ships. ExxonMobil also signed deals with Qatar to partner in the construction of two new LNG trains in 2002, and in 2003 entered into a partnership agreement to supply LNG to the U.S. market.
Meanwhile, while other companies filed permit applications with the Federal Energy Regulatory Commission (FERC) to build new LNG regasification terminals in the U.S., operators of two pre-existing facilities embarked on major expansions.
Southern LNG began initial LNG imports in the early 1970s, but ceased import operations by mid-1980. Located just a few miles from Savannah, Georgia on Elba Island, Southern LNG was authorized by FERC to restart import operations in 2000. By mid-2003, the facility had applied for and received a FERC permit to conduct a significant expansion, “which included adding a second and third docking berth, a fourth cryogenic storage tank, and associated facilities.”
In Feb. 2006, El Paso Corporation, which was then the owner of the facility, announced the startup of its expanded facility, Elba II, at a cost of $157 million. At the same time, El Paso announced it had applied to FERC for the permit necessary to build an Elba III facility that would double its ability to import LNG to the U.S.
Dominion Energy’s Cove Point facility first began operations to import LNG into the United States in 1978. Located in Chesapeake Bay off the coast of Maryland, this offshore facility receives imports of LNG, regasifies the product offshore and then ships the gas onshore via pipeline. By 1994, changing market conditions led to the decision to cease imports of LNG and convert Cove Point into a storage facility for domestically-produced natural gas.
But by 2001, the market had changed once again, and Dominion and various customers agreed to restart its import operations. With the construction and opening of a new LNG storage tank, Cove Point began to bring in new shipments of LNG by the end of 2003. FERC authorized further expansion of Cove Point’s import capacity in 2006, a little more than a year after a Texas company named Range Resources had announced its history-changing initial commercial well drilled in the Marcellus Shale.
Several other companies made applications for FERC for permits to build new LNG import/regas facilities, but only a handful were able to get off the ground. Those operators, along with Dominion and El Paso couldn’t know it in early 2006, but Range Resources’ new discovery meant the market was about to shift again, and in a very dramatic fashion.
The Shale Revolution Kicks Into High Gear
Throughout the decade of the 1990s, the big hope for onshore development of U.S. natural gas lay in coalbed methane formations like the Fruitland Coal in northwest New Mexico/southeast Colorado, the Powder River Basin in Wyoming and Alabama’s Black Warrior Basin. These “coal seams,” as those in the industry referred to them, were relatively shallow layers that were easy and inexpensive to drill and produce, so companies like Burlington Resources, Devon Energy, Amoco (before it was sold to BP), and others loved them.
The methane in the typical coal seam is held in place by hydrologic pressure. Thus, to produce the gas, companies would drill vertically into the formation and perform a light hydraulic frac job to break up the rock and cause the water flow out from it. As the formation was de-watered, the methane would release and begin to flow. The process was non-complex, easily repeatable and produced gas in significant quantities from the wells drilled in the “fairway” of the basin, i.e., the deepest parts of the seam. Wells outside of the fairway were less productive but still worth drilling.
The biggest issue was where to properly dispose of the often-vast quantities of water produced by each well, but the water was so clean in most places that it was appropriate for agricultural use.
Another big issue was the steep decline rates and relatively short life of each well. The “fairway” wells would come on like gangbusters for several months, but within a year’s time most had slowed dramatically. This meant that producers would have to drill additional wells at a rapid pace just to maintain current production levels.
By the end of the decade, it had become apparent that the industry was beginning to run out of exploitable coal seams to produce in the U.S. This dynamic led to a great deal of concern among policymakers that natural gas was not a fuel the country could rely upon to carry a growing share of the country’s power-generation load into the future, which helps explain why the NPC received requests for natural gas-related studies from two different Energy Secretaries in a span of just four years, and why the 2003 study’s outlook was that the domestic industry would not be able to supply the country’s demand for natural gas without steadily-increasing imports of LNG.
That all began to change on Nov. 10, 2004, when Range Resources completed its initial commercial well into the Marcellus Shale formation. Range brought in the Renz 1 well in a rural area of Washington County, Pennsylvania by employing the same combination of horizontal drilling and hydraulic fracturing that had led to the successful development of the Barnett Shale in north central Texas over the prior half-decade.
By early 2005, the race was on among a number of upstream companies to obtain leases and start drilling Marcellus wells of their own, and the entire outlook for natural gas in North America had forever changed. By 2007, the Marcellus was yielding more than a billion cubic feet (bcf) of natural gas each day. That rose to two bcf per day by 2010, four bcf per day by 2012 and about 16 bcf per day by 2015.
At the same time, per-well recoveries were rising dramatically to such an extent that overall Marcellus output kept growing at an increasingly-rapid pace even as the rig count crashed along with natural gas prices starting in early 2012. By 2014, a regional rig count that had once risen to more than 140 had dropped below 100. By 2019, that count sat at 60.
In 2008, Chesapeake completed the first commercial well in the Haynesville Shale, and the next race to lease and drill for dry natural gas was on. In contrast to the Marcellus region, where production growth was slow for several years due to a lack of midstream infrastructure, the Haynesville is located in a region that had seen significant natural gas production for decades from the prolific Bossier and Cotton Valley formations. Because the Haynesville had a pre-existing pipeline infrastructure to tie each new well into, the formation added another six bcf of gas per day onto the mark by 2011.
Next up in the procession of major new natural gas shale formations to be discovered was the Eagle Ford Shale play, whose first commercial well came on-line later in 2008. Spanning a 23-county area of south and central Texas, the Eagle Ford is thought of mainly as an oil-producing formation today. But that is mainly due to the heavy focus on liquids production in recent years as the oil price has firmed up while the price for natural gas has largely stagnated at sub-$3.00 per mmbtu levels. That first producing well was in fact a gas well, and several months had gone by before producers discovered that the Eagle Ford would become one of the biggest oil plays in U.S. history.
As most know by now, the Eagle Ford formation is divided into three distinct producing areas. The northwestern third, and shallowest part of the formation produces a beautiful grade of light, sweet crude oil with very little associated natural gas. The center third of the play area — the “wet gas” piece of the formation — has already produced great quantities of natural gas, along with its associated condensate and other natural gas liquids. Meanwhile, the deepest part of the formation, the southeastern third that produces only dry gas, has today gone largely unexplored because of low gas prices.
In reality, this part of the Eagle Ford is a sort of insurance policy for the industry, an untapped natural gas reserve that will ultimately be produced as the country’s other huge formations begin to play out and prices improve. That may be decades in the future, but, for the time being, the Eagle Ford continues to add to the U.S. natural gas supply mainly from its “wet gas” region, and ranks as the third-largest natural gas-producing basin.
The final piece of the current U.S. natural gas supply puzzle began its discovery process in late 2009/early 2010, as Permian Basin producers who owned pre-existing leasehold held by production from the region’s many previous oil booms began to testing the Spraberry, Wolfcamp and Wolfberry formations using the same drilling/fracking techniques previously applied in other shale regions. As has been well-reported by so many, the result has become the most spectacular oil boom in the U.S. since the early 1980s, and the largest boom Texas has seen since the days of Spindletop and the East Texas field.
Less reported and commented upon has been the fact that all of these “oil” wells also produce a remarkable amount of associated natural gas. As I mentioned earlier in this piece, the resulting production is so substantial that the oil-rich Permian Basin, far and away the largest oil field ever discovered in North America, also ranks today as the second-largest natural gas-producing basin in the U.S.
Taken together, the advent of this shale revolution, combined with the ongoing process refinements and technological advances that enable producers to squeeze higher and higher volumes out of each additional well, has created a sea-change in the U.S. supply picture for natural gas. Where the 2003 NPC study correctly identified a situation characterized by increasing shortage of available supplies and rising need to import LNG, today’s market is one of supply abundance for as many decades as any economic model could hope to calculate, and a new and growing bonanza in the business of exporting the commodity to countries all over the globe.
The LNG Export Opportunity
As one would expect, the business of importing natural gas into the United States became a growth industry in the wake of the NPC study. The business reached a zenith in April, 2007, when about 3 billion cubic feet of gas per day was brought into the U.S. through Cove Point, Southern LNG and a small number of other facilities that had gotten off the ground by that time.
But the birth of the shale revolution and the new abundance of U.S. natural gas supply it created brought about a new opportunity to reverse the flow of LNG and ship it out to other markets. This shift did not come about easily or quickly, largely due to the intervention of politics and politicians, as so often happens when major market shifts take place.
As one might imagine, industrial and manufacturing users of natural gas in their processes were not anxious to see U.S. producers endeavor to create stronger prices for their production by opening new markets. Political opposition came from some of the biggest companies in the chemicals, fertilizers and plastics industries, businesses with sophisticated lobbying arms that are able to apply heavy pressure on policymakers.
Due largely to this political opposition, companies looking to convert their existing LNG import facilities into export facilities, and companies that, like Cheniere Energy, wanted to build entirely new LNG export infrastructure found the process of obtaining the necessary permits from the Department of Energy (DOE) and FERC to be painfully slow and costly. The reality that the Obama Administration had no particular interest in encouraging the growth of the U.S. oil and gas business sector also contributed to the slowness of the process.
Also, as the Oil and Gas Journal noted in an article published in Dec. 2012, the permitting process included more than just DOE and FERC:
“Cheniere Energy Inc. successfully completed approval processes for export capacity at its Sabine Pass plant in Louisiana. Approvals included a water quality certificate from Louisiana, a permit from the US Corps of Army Engineers for working in wetlands, state endangered species clearance from the Louisiana Department of Wildlife and Fisheries, an air emissions permit from the Louisiana Department of Environmental Quality, and a National Historic Preservation Act Clearance from the Louisiana Department of Culture.”
The construction of these multi-billion-dollar facilities also takes time. It took four years for Cheniere Energy to go from getting its final permit approval in place to being ready to ship out the historic first cargo from its Sabine Pass LNG facility in Feb. 2016. But from that point forward, the volumes of U.S. LNG exports have skyrocketed, going from 3.3 bcf of natural gas in Feb. 2016 to almost 108 bcf in Nov. 2018.
Since opening its first export train at Sabine Pass, Cheniere has been in constant expansion mode at that location. The facility’s first three liquefaction trains are now fully on-line and the company’s development plan calls for a total of seven liquefaction trains to be operational by 2022.
Cheniere also recently began operations at its new Corpus Christi Liquefaction facility, having shipped out its first cargo there in Dec. 2018. When fully operational, the Corpus Christi facility will boast three liquefaction trains, with as many as seven more on property adjacent to the main facility, which Cheniere refers to as its Corpus Christi Stage 3 project.
Dominion’s reconfigured facility at Cove Point became the second major U.S. liquefaction plant to export shale gas when it commissioned its initial cargo bound for London in March 2018. The Cove Point facility has a storage capacity of 14.8 bcf of gas, and the ability to ship out as much as 1.8 bcf per day.
Once the permitting logjam at the federal level was broken in late 2012, the pace of awarding permits accelerated during the latter years of the Obama administration.
U.S. capacity for LNG exports will only continue to expand in the coming years. Half a dozen major new facilities are in the final stages of planning or early construction stage in places like Freeport, Texas; Golden Pass, Texas; Cameron Parrish, Louisiana; Pascagoula, Mississippi; and at Southern LNG in Alabama, a facility now owned by Kinder Morgan.
By April of 2018, U.S. facilities had sent shipments of LNG to no fewer than 27 different countries around the world, with the majority of the volumes headed for South Korea, Mexico, Japan or China. While U.S. exporters face stiff competition from major exporting countries like Qatar and Australia, the potential for future growth is strong.
The Best is Still to Come
While the growth of natural gas exports has thus far failed to produce stronger commodity prices here at home, there is no doubt this growing business benefits the U.S. economy. A study conducted by DOE released in June 2018 found that:
• U.S. consumer well-being increases with rising LNG exports.
• Total U.S. economic activity (gross domestic product) increases with rising LNG exports.
• U.S. LNG exports are backed by increased natural gas production here at home.
Todd Snitchler, Director of Market Development for API, summed up the study thusly:
“This report further confirms that increasing exports of American natural gas will benefit the U.S. economy and benefit consumers. U.S. LNG cargoes have already been delivered to more than 25 countries spanning every region of the world. Increasing the use of American energy throughout the world enhances our national security here at home and abroad by giving our allies a reliable source of natural gas. Further, the increased use of clean natural gas has lowered U.S. emissions to levels not seen in 25 years. With global emissions on the rise, increased use of U.S. natural gas around the world could help make the world’s air cleaner.”
Nor will the availability of sufficient domestic natural gas resources serve as any sort of limiter on the growth of LNG exports in the coming decades. Fifteen years after the drilling of the first successful Marcellus Shale well, the industry is still in the early stages of determining the true scale of the available shale gas resource.
As a part of conducting its major advertising campaign promoting natural gas a decade ago, America’s Natural Gas Alliance liked to say that “America has 100 years of natural gas supply” in its messaging. That is a severe understatement. The truth is that America has several centuries of supply that the industry currently knows about, and more is being discovered with every passing day.
When we conducted that NPC study on natural gas back in 2002-2003, one of the questions Secretary Abrahams wanted us to answer was whether our country’s available supply of natural gas would enable it to serve as a so-called “bridge fuel,” a fuel source that would help our electric power sector successfully transition from its then-extant fuel mix that was heavy on coal and nuclear to an envisioned new world dominated by renewable power sources.
Today, the thought that this clean and amazingly abundant fuel source should be limited to a “bridge” role is arcane and outdated. Thanks to its displacement of more than 53 gigawatt hours of coal-fired generating capacity since 2012, natural gas now ranks as the leading coal-fired generating capacity since 2012, natural gas now ranks as the leading source of U.S. power generation, according to the EIA.
That equation is not going to change anytime soon, nor should it. The shale revolution has provided our country — and other countries around the world — with an amazing gift, a commodity that benefits our society, economy and environment in innumerable ways.
Better yet, this revolution is just a little more than a decade old, and still in its early developmental stages. What has transpired so far has been amazing, but the good news is that the vast majority of the opportunity remains unfolding before us.
About the author: David Blackmon is the Editor of SHALE Oil & Gas Business Magazine. He previously spent 37 years in the oil and natural gas industry in a variety of roles — the last 22 years engaging in public policy issues at the state and national levels. Contact David Blackmon at [email protected].
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