UPSTREAM NEWS

Shale gas provides largest share of US natgas production in 2013

"Total US natural gas gross withdrawals reached a new high at 82 bcf/d in 2013, with shale gas wells becoming the largest source of total natural gas production. Natural gas gross withdrawals are a measure of full well stream production including all natural gas plant liquids and nonhydrocarbon gases after oil, lease condensate, and water have been removed. According to the Natural Gas Annual, gross withdrawals from shale gas wells increased from 5 bcf/d in 2007 to 33 bcf/d in 2013, representing 40% of total natural gas production, and surpassing production from nonshale natural gas wells." - EIA

Margins squeezed even tighter for upstream companies

Despite a record year of capital investment totaling more than $720 billion in 2013, which represented an 18% increase above 2012 investments, companies operating in the global upstream energy industry saw their margins squeezed even tighter than in 2012, as costs continued to escalate rapidly while profitability declined, according to analysis from IHS.

"Margin squeeze remains a significant challenge for upstream energy companies because capital spending continues to rise rapidly, despite the recent weakening in per-unit profitability and the longer-term trend of deteriorating returns," said Daniel Pratt, CFA, director of energy company transaction research at IHS, and a co-author of the IHS report, the 2014 IHS Herold Global Upstream Performance Review. "If it persists, the recent price drop in global crude prices will only add to these financial challenges for operators."

The Performance Review assessed three key areas of upstream performance - capital investment, reserve replacement rates and costs, as well as profitability, which are discussed from a peer group, individual company, and regional perspective.

The accelerated spending, according to the IHS review, has caused the underlying net capitalized costs of upstream assets to more than triple during the last decade. This increase, coupled with lower per-unit profitability, has caused return on net cumulative capitalized costs to decline since 2005. In fact, returns during the past five years have been markedly lower than what the industry achieved for much of the past decade.

In 2000, the IHS study universe earned a 23% net income return on net cumulative capital costs when realized costs were just above $22 per barrel of oil equivalent (BOE). Since then, realized prices nearly tripled to $63 per BOE in 2013, yet IHS results indicated the study universe earned only an 11% return on net cumulative capital cost.

Said Pratt, "History shows that it will take a significant reduction in organic capital spending before costs are meaningfully reduced," and the recent drop in oil prices, if sustained, could be a catalyst for this. "We were previously expecting a 2% decline in exploration and development spending in 2014, based on an IHS survey of 50 of the largest global upstream companies. However, if this recent drop in oil prices continues for any length of time, we would expect to see weaker capital spending this year and into 2015."

Aside from the increasing challenge of cost containment, Pratt said that one of the most significant challenges for operators is finding opportunities for growth, "viable growth opportunities appear to be shrinking because Russia was the only region outside of the highly competitive landscape of North America to show any meaningful reserve growth during the past decade."

From 2004 to 2013, he noted, the companies included in the IHS study were only able to grow reserves in Canada, the US, Russia, and Asia Pacific, where compound annual growth rates during the past decade totaled 9%, 5%, 5%, and 3%, respectively. The unconventional revolution, coupled with the large resources associated with oil sands, has made North America a growth region once again.

Another hurdle facing upstream energy companies, said the IHS report, is available cash flow for investment in organic growth. Since reaching a peak of more than $136 billion in 2008, the free cash flow available to the industry after investing in organic growth has been generally declining. During the first half of the past decade, operators were remarkably consistent in investing 75% of their cash from upstream operations back into organic finding and development activities that include non-proven reserve acquisitions, as well as exploration and development drilling. However, during the latter half of the decade, IHS said, that allocation has ballooned to an average of 91% of cash flow, and nearly 100% in 2013.

"As a result, organic finding and development activities generated essentially no free cash flow in 2013," Pratt said, "which will have an immediate impact on broader capital strategies and could have longer-term impact on the regional growth outlooks as less capital is available for future growth investments. In terms of shareholder satisfaction, the decline in cash flow also has implications on non-upstream uses of capital, such as share repurchases and dividend distribution to shareholders, which are often major elements of a company's capital strategy and its ability to return value to shareholders."

Rosneft (Russia) led all companies studied by investing $86 billion in 2013, including $74 billion in proved and unproved acquisition spending, primarily for TNK-BP. The Chinese National Offshore Oil Co. (CNOOC) Ltd. followed Rosneft in capital spending in 2013, with $40 billion invested in total, which includes acquisition spending of $25 billion, primarily for Nexen. Royal Dutch Shell, PetroChina, Exxon Mobil, Chevron, Total, Petrobras, BP, and Statoil ASA rounded out the IHS top-10 list of leaders for capital spending in 2013.

Chevron increased its spending more than 30% in 2013 by $8 billion to $33.5 billion, virtually all of it development spending. The biggest increase was in the Asia Pacific region, where Chevron is developing the Gorgon and Wheatstone LNG projects. Total SA also increased its spending more than 30% in 2013, to $30.8 billion, IHS said. Total's increased investment was for projects in Europe, Africa, the Middle East, and Asia, with the latter including the Japan-based Inpex-operated Ichthys LNG project and the Santos-operated Gladstone LNG project, both in Australia.

Among the exploration and production (E&P) peers, Inpex more than doubled its capital spending to $6.4 billion by investing $2 billion in unproved property purchases. Russia/Caspian-based Novatek doubled its capital outlays by buying proved reserves, including a 49% equity stake in ZAO Nortgas. US E&P's Oasis Petroleum and Rosetta Resources more than doubled their capital investments in 2013. Rosetta Resources spent nearly $1 billion in acquisitions, much of that for Comstock Resources' West Texas assets. Oasis Petroleum invested nearly $2 billion in acquisitions, including Zenergy's Williston Basin assets for $1.45 billion, IHS said.

On a regional basis, US capital spending declined in 2013 to $177 billion because acquisition expenditures were $33 billion lower than in 2012. Exploration and development spending in the region was essentially flat at $146 billion. Without CNOOC's acquisition of Nexen, Canadian investment would have decreased because exploration and development spending was down and the overall market was weak, said the IHS report. Africa and Middle East development spending in 2013 was the highest in recent years, but the gain was nearly offset by lower acquisition and exploration outlays, IHS said. Asia Pacific capital spending rose 6% because a 9% increase in development spending offset a decline in unproved property purchases and a modest 4% gain in exploration outlays.

South and Central America capital spending grew a robust 27% on increases in all categories. Acquisition spending nearly tripled to $5.2 billion on purchases by Royal Dutch Shell and Pacific Rubiales. Exploration spending was up 37% in the region to $17.3 billion and development spending increased 16% to $46.4 billion. Europe is experiencing a renaissance of upstream investment, with companies reporting a six-fold gain in acquisition spending and a 26% gain in exploration outlays. Capital outlays in the Russian and Caspian region surged from the lowest of all regions in 2012, to the second highest in 2013. Rosneft's purchase of TNK-BP was the main factor, but development spending also increased 23% to $31.3 billion.

Chevron makes oil discovery in deepwater GOM

Chevron Corp. has made a new oil discovery at the Guadalupe prospect in the deepwater US Gulf of Mexico. The Keathley Canyon Block 10 Well No. 1 encountered significant oil pay in the Lower Tertiary Wilcox Sands. The well is located approximately 180 miles off the Louisiana coast in 3,992 feet of water and was drilled to a depth of 30,173 feet. The Guadalupe well was drilled by Transocean's Discoverer India deepwater drillship. "Chevron subsidiaries are among the top producers and leaseholders in the Gulf of Mexico, averaging net daily production of 143,000 barrels of crude oil, 347 million cubic feet of natural gas, and 15,000 barrels of natural gas liquids during 2013," said Jeff Shellebarger, president, Chevron North America Exploration and Production Company. Chevron subsidiary Chevron USA Inc. began drilling the Guadalupe well in June 2014. Chevron USA Inc., with a 42.5% working interest in the prospect, is the operator of the Guadalupe discovery well. Guadalupe co-owners are BP Exploration & Production Inc. (42.5%) and Venari Resources LLC (15%).

CNOOC reports first oil from GEAD

CNOOC Ltd. reported that the Golden Eagle Area Development (GEAD) in the UK North Sea has begun production. The GEAD includes development of the Golden Eagle, Peregrine, and Solitaire fields. The fields are located in blocks 20/1S, 20/1N and 14/26a of the North Sea, and are located 70 kilometers northeast of Aberdeen, UK, with an average water depth ranging from 89-139 meters. The development comprises separate production and wellhead platforms and two subsea production systems. A total of 15 production wells and six water-injection wells will eventually be drilled from these facilities. Currently, there are two Golden Eagle wells producing 18,000 bbl/d. The project is expected to reach its peak production rate of 70,000 bbl/d in 2015.

STO makes gas discovery offshore Tanzania

Statoil announced seventh offshore gas discovery off the coast of Tanzania. The find, made with Exxon Mobil, marks an additional 1.2 tcf of natural gas at the Giligiliani-1 well off the coast of Tanzania on the western side of Block 2. The discovery was made in a total water depth of 8,202 feet and increases the total in-place volumes to as much as approximately 21 tcf in Block 2.

GDF SUEZ, BP make North Sea find

GDF SUEZ E&P UK Ltd and BP have made an exploration discovery in the UK Central North Sea. The exploration well (30/1f-13AZ) encountered hydrocarbons in a Palaeocene sandstone reservoir in block 30/1c (license P363 operated by BP) and a subsequent side-track into block 30/1f (license P1588 operated by GDF SUEZ E&P UK Ltd) confirmed the westerly extension of the discovery. The discovery flow tested at a maximum rate of 5,350 boe/d. The well was drilled by GDF SUEZ E&P UK Ltd as operator under a joint well agreement between the two license groups.