2013 Outlook on Oil & Gas
My take: By John England
Global demand for energy continues to grow, especially in developing countries such as China and India, as the oil and gas industry continues to search for new sources of energy. Increasingly, oil and gas are found in challenging areas, such as deep water, arctic regions and politically challenged regions of the world.
For the past five years, however, the headline for the industry has been the dramatic development of unconventional oil and gas in the U.S., such as shale gas and tight oil. Unlocked by technological advancements, development of these resources continues to change the global landscape of oil and gas.
Impact of the shale revolution
As a result of the “shale revolution” in the U.S., domestic dry gas production increased 25 percent from 2007 to 2012. According to the U.S. Energy Information Administration (EIA), domestic production of dry natural gas reached an all-time high of over 65 billion cubic feet per day (Bcf/d) in July 2012. Natural gas volumes continue to swell U.S. storage capacity with working natural gas in storage at 88 percent of total capacity.1 One important result of the surge in natural gas production is the natural gas price has become uncoupled from the oil price in the U.S. while natural gas is still priced off of crude oil in the rest of the world. In April 2012, as oil prices surged and natural gas prices plummeted, the U.S. oil-to-gas price ratio rose to a high of 53 in absolute terms and over nine in energy-equivalent terms.
However, the supply of dry gas on the market is expected to continue to grow even under a weak natural gas price scenario. This is due to the fact that dry gas is produced as a by-product of development from still profitable liquids-rich shale plays. According to the U.S. Energy Information Administration (EIA), an average wet shale play in the U.S. with 35 percent liquids content produces around 11 thousand cubic feet (Mcf) of dry gas per barrel of natural gas liquid (NGL) produced. During 2007-12, Baker Hughes reported that the horizontal rig count, the type of rig predominantly used in shale gas plays, tripled while the natural gas rig count fell to a 13-year low. U.S. dry gas production and horizontal rig count data for the past five years show a correlation of 92 percent.2 As a result, associated gas from liquids-rich shale plays is expected to triple from 2006 levels by 2020.3
To maintain profitability, oil and gas companies have turned from dry gas production, which is largely uneconomic at current prices, to the production of the liquids portion of shale gas formations. Here too, shale gas is again revolutionizing the market. Bentek has forecast that natural gas liquids production will increase by 500,000 barrels per day (bbl/d) to 3.1 million barrels per day (MMbbl/d) in 2020, of which 50 percent will be ethane. As a result of increasing liquids production, natural gas liquids products (ethane and propane) are themselves becoming uncoupled from the oil price. In July 2012, ethane sold for 30 cents per gallon, a 60 percent decline from the prior year.4 The propane market is also experiencing price declines with prices falling 20 percent from April to May 2012.5 At the Conway, KS hub the ethane-propane mix registered a near 30-year low at just two cents per gallon.6
The surge in liquids production is the result of continued innovation in the industry as it perfects the art of extracting the most resources from each shale formation. Technological innovations such as longer laterals, multi-well pads and multi-stage fracturing have reduced the full-cycle cost of shale gas wells by 40-50 percent compared to conventional wells, and more than doubled their average initial production rates to 60-80 million cubic feet per day.7 The entry of research and development (R&D)-focused super majors and increased capabilities of service companies will continue to lower operating costs and increase well productivity. In 2008, a well in the Fayetteville shale was estimated to produce 1.8 Bcf of natural gas over its 30-year life. However, improvements in drilling technologies have increased that estimate to 3.2 Bcf per well.8
The market should prepare for produced volumes to rise even higher. The majority of the 19 recognized basins are still in early exploratory or development stages. Moreover, production is still ramping up in Marcellus, the largest U.S. shale gas basin. In July 2012, EIA data showed that Marcellus production exceeded Haynesville and reached 7.4 Bcf/d (compared to less than 3 Bcf/d in 2011).
The growth in midstream pipeline and processing infrastructure has not kept pace with shale gas growth, which has led to stranded gas supplies or increased flaring of natural gas. In 2011, approximately 35 percent of North Dakota's natural gas production was flared or otherwise not marketed due to insufficient infrastructure.9 The Interstate Natural Gas Association of America (INGAA) projects that a total of $200 billion in midstream investments will be required to accommodate the development of U.S. natural gas resources from 2012 to 2035.
As a result, ethane rejection (where ethane is sold as part of the natural gas stream rather than as a liquid) is increasing in regions such as the Marcellus shale. Some companies in the Marcellus region are rejecting well over half their ethane production.10 Other producers are burning ethane onsite in the absence of takeaway capacity or using it for compression or production.
It is clear that U.S. natural gas supply growth is outpacing demand growth, resulting in decade-low prices and peak inventory levels. EIA data shows that since 2007, total supply increased by 25 percent while demand rose by only 5 percent. U.S. natural gas prices plunged below $2 per 1 million British thermal units (MMBtu) in April, and inventories reached 3.2 trillion cubic feet (Tcf) in early August, 12.5 percent higher than the five-year average. Even crude oil production in the U.S. is at a 15-year high of over 6.5 MMbbl/d, according to EIA.
An increasing solution to burgeoning domestic production of both natural gas and crude oil as well as lagging domestic natural gas and petroleum products demand is to export. Oil and gas companies have applied for new liquefied natural gas export licenses with the U.S. government in order to profit from the price disparity between the U.S. domestic natural gas price and the foreign natural gas price, which is over $15 per MMBtu in Asia. Even factoring in an upper limit of $3.00 per MMBtu for liquefaction as well as estimated shipping costs of $1.50 per MMBtu to Europe and $3.75 per MMBtu to Asia, U.S. natural gas producers can still reap substantial profits from these transactions.11
“Successful oil and gas companies are embracing the current price environment and finding new sources of demand in order to profit from shale gas.”
Currently, the government is considering permit applications that total 20 Bcf/d, which if approved would make the U.S. the largest natural gas exporter in the world when just five years ago, the country was preparing to become the world’s largest natural gas importer. The impact of U.S. exports on global natural gas markets is not yet known.
The export potential for oil and gas companies does not end there. According to EIA data, while domestic petroleum products demand fell 20 percent, U.S. refinery output remained flat, averaging >15 MMbbl/d during 2006-12 as U.S refiners discovered profitable export markets for surplus production. From 2006 to 2012, U.S. exports of petroleum products have tripled from 1 MMbbl/d to 3 MMbbl/d with Latin America being the largest and the fastest growing export market for U.S. refiners driven by strong distillate demand in Mexico, Brazil and Chile.
Low-priced natural gas from shale is helping to fuel the growth in petroleum products exports. Gulf Coast refiners benefit both from lower U.S. natural gas prices and a higher percentage of natural gas in the feedstock. Gulf Coast refiners’ gas-related feedstock cost fell by nearly 60 percent since 2008 due to the steep fall in U.S. natural gas prices. During the same period, the equivalent feedstock cost for a European refiner increased 12 percent due to higher natural gas prices in the region and continued use of oil-linked feedstock for process fuel. The decline in gas prices since 2008 has doubled the feedstock advantage of Gulf Coast refiners over European refiners from around $1.25 a barrel to $2.45 per barrel.12
Successful oil and gas companies are embracing the current price environment and finding new sources of demand in order to profit from shale gas. Deloitte continues to be at the forefront of the growth in unconventional oil and gas resources, and we are focused on assisting our clients develop strategies that will position their companies for a profitable future.
1. EIA, Natural Gas Weekly Update, October 11, 2012
2. Deloitte, Market Insights Analysis
3. Petroleum Economist, "North America's gas producers look to liquids for salvation," Shaun Polczer, July 9, 2012
4. Bloomberg data
7. IHS Global Insight, "The economic and employment contributions of shale gas in the United States," prepared for America’s Natural Gas Alliance, December 2011
8. James Mason, energy consultant, “Well production profiles to assess Fayetteville gas potential revisited,” Oil and Gas Journal, May 7, 2012
9. EIA, Today in Energy, “Over one-third of natural gas produced in North Dakota is flared or otherwise not marketed,” November 23, 2011
10. Platts, Energy Spotlight Podcast, "Ethane rejection in the U.S. Marcellus Shale," August 17, 2012
11. Deloitte, Market Insights Analysis
As used in this document, “Deloitte” means Deloitte LLP [and its subsidiaries]. Please see www.deloitte.com/us/about for a detailed description of the legal structure of Deloitte LLP and its subsidiaries. Certain services may not be available to attest clients under the rules and regulations of public accounting.