Finding, developing and producing oil and gas reserves is the prime directive of upstream energy companies. The oil business is very capital intensive with more than its fair share of relative risk. Energy companies can add reserves through exploration or acquisition, with each carrying their own sets of inherent challenges. As a key part in asset allocation and strategy for oil and gas companies, acquisitions and divestitures (A&D) vary by the year. 

In E&P acquisitions, the basic considerations received for an asset does not necessarily represent value. It is futile to fully assess the value of a property before intensive exploitation and development of an asset has commenced. An acquisition bidder approximates asset value based on a variety of factors, including assumed commodity prices,  development costs, available reliable technology, environmental standards, fiscal terms and regulatory constraints, among others. 

The focus of this article is to review the recent trends in North American A&D between the January 2013 to July 2018 time period, filtered to deals that were executed at a value in excess of $100 million. The reason this time period was chosen in order to study changes in transactions metrics as WTI oil prices plunged from over $103 per barrel (/bbl) in August 2014 to $30/bbl in January 2016, commodity prices have since recovered and are in the mid $60/bbl to $70/bbl range. From our analysis we observed that certain U.S. regions have garnered more attention and dollars for acquisitions based on the industry’s perceived value of the region. The Permian Basin is the most active region in the last six years, both in terms of dollar value of transactions and deal flow.

Figure 1: 2013-2018 A&D deal value by region (Source: PLS M&A Database)

Figure 1 shows the summation of deal values over the 2013-2018 period, excluding Alaska and west coast regions, where the illiquid A&D markets, limited transactions and insufficient willing buyers and sellers have affected the prospects of the energy industry within these regions as reflected in declining oil production rates.

The Delaware and Permian Basins (Permian region) have been the site of major acquisitions. Major deals that were recently transacted in the Permian region include: Concho’s acquisition of RSP Permian ($9.5 billion); Encana’s acquisition of Athlon Energy ($7.1 billion): and Exxon’s acquisition of Bass company’s acreage ($5.6 billion). Some of the most active Permian dealmakers by number of deals in excess of $100 million deal sizes were Parsley Energy (12), Diamondback Energy (8), Callon (5) and Concho Resources (5). Figure 2 shows the number of transactions by county with the hotter colors representing higher transaction intensity.

Figure 2: 2013-2018 heat map of number of transactions (Source: PLS M&A Database)

According to the U.S. Energy Information Administration (EIA), new well production per rig started to rise in the Permian region since 2013. The number peaked in 2016 as the rig count in this region was at its lowest number in the decade and has since then dropped. However, more recently, the metric rose every month from July 2017 through July 2018, with new well production per rig of 562 bo/d and 1.235 million cubic feet per day (MMcf/d) of natural gas in August 2018. However, the EIA projects that productivity will not rise in the near term likely due to infrastructure constraints. Significant investments in midstream infrastructure are currently being made by the industry in this region, which should ameliorate the takeaway capacity situation.

Figure 3: North American oil weighted transactions vs. implied reserve value in $/proved BOE (Source: PLS M&A Database)

Figure 3 shows the oil weighted deal values based on the announcement date and the implied proved reserves value ($/proved BOE) for the transaction period. As oil prices declined in the Q3 2014 to Q1 2016 period, deal flow dried up while public companies focused on rationalizing their portfolio of assets, streamlining operations and reducing their G&A (general and administrative) budget. Many private equity and private equity-backed ventures entered the market during this period and acquired assets considered “non-core” by majors and public independents. The average implied acquisition price per proved BOE during the 2013-2018 period is around $14.47/BOE for oil weighted assets. The period between Q2 2016 and Q4 2017 was a favorable period to acquire oil-weighted assets as WTI oil price stabilized in the $50/bbl range. 

Gas-weighted deals on average transact on lower $/proved BOE numbers than oil weighted deals, though some of the largest deals transacted over the 2013-2018 time period reviewed appear to be gas weighted. The Repsol-Talisman energy deal ($12.8 billion) closed in Q4 2014 was a multi-region deal with a significant North American gas shale component, including the Marcellus and Eagle Ford acreage in the U.S. The international component included Canadian assets (Duvernay, Motney, Greater Edison, Chauvin and Lorraine/Utica), Southeast Asian and Norwegian assets. Among the more recent gas deals that were struck in Q2 2017 included EQT’s acquisition of Rice energy ($8.2 billion) consolidating acreage in the Eastern region of the U.S. Another prominent deal in this time period was the Hilcorp/Carlyle acquisition of ConocoPhillips’ acreage in the San Juan Basin of northwest New Mexico ($2.7 billion), acquiring legacy gas assets with upside liquids rich potential in the Mancos shale.

Figure 4: North American gas weighted transactions vs. implied reserve value in $/proved BOE (Source: PLS M&A Database)

The proved reserves purchase price for gas-weighted assets appear to be on a declining trend as U.S. gas supply reached an all-time historic high at 81.2 billion cubic feet per day (Bcf/d) in August 2018 buoyed by stellar wells in the Marcellus, Utica and Haynesville shale plays. As trade in liquified natural gas (LNG) continues to increase, there should be more global equalization of natural gas prices and improvement in domestic natural gas prices, thus consequently improving value for natural gas assets in the A&D market.

Figure 5: Average $/acre heat map (Source: PLS M&A Database)

Figure 5 shows the average $/per acre for the transactions in the 2013-2018 time period. We can conclude that the Permian region is one of the costlier areas to enter into due to higher-than-average cost/per acre valuations. Acreage values were not available for every transaction and, for this reason, some of the counties are in a light shade of grey. 

Some of the most active sellers in the U.S. A&D market may be grouped into two buckets: 

1. Companies trying to rationalize their portfolio of assets (i.e., Cheseapeake, BHP Billiton, Anadarko, Apache); and
2. Companies that were regionally-focused acquisition candidates (i.e., Rice Energy, RSP Permian, Athlon Energy and Kodiak Oil & Gas). 

Several energy companies that made material acquisitions during the 2013-2014 period had to face the pain in terms of lagging stock price values or even bankruptcy proceedings as energy prices tumbled in the subsequent years. Some notable attributes of successful buyers in the energy space are companies that have a long-term plan and vision, adequately hedge their acquisitions, understand the cycles of commodity prices and are disciplined contrarian investors. 

A&D = Opportunity

A&D offers the opportunity to develop complementary land positions in major shale plays, build economies of scale, marry capital with opportunity, introduce new technologies and workflows to improve well productivity and grow production. In conclusion, A&D valuation trends reflect the forward-looking goals of energy companies in 2018-2019 and beyond. With the U.S. expected to export more energy in the future, there is a positive outlook for North American A&D in a more globally connected economy.