Recent Upstream Trends in the Gulf Coast Region

Gulf Coast oil and gas production continues to dominate the upstream sector, with three of its basins, the Permian, the Eagle Ford, and the Haynesville Shale, recently reaching notable milestones. The Permian Basin achieved record output levels in May of this year for both its oil and gas production. The US Energy Information Administration (EIA) estimated that the Permian’s crude oil production would reach 5.7 MMbpd (million barrels of oil per day) and that its gas output would reach 22.5 BCF/d (billion cubic feet per day) during that month. The Haynesville Shale, the third-largest natural gas-producing basin in the United States, reached a record high of 14.5 BCF/d in March 2023. The EIA forecasts that both basins will likely experience slower production increases from June to July 2023. As for the Eagle Ford Shale, the basin achieved the largest upstream M&A deal in the first quarter with Baytex Energy’s acquisition of Ranger Oil Corp. Several factors signal positive trends within the Gulf Coast’s upstream region, such as profitable deal-making and increased output, but there are also various challenges relating to (i) financing acquisitions and operations; (ii) acquiring a reduced amount of remaining inventory; and (iii) balancing environmental impacts with increased production.

Strong start for acquisitions

The Gulf Coast region experienced a profitable first quarter, with the Eagle Ford stepping forward as the leading deal maker. Out of the USD8.6 billion transacted in upstream deals across the United States, the Eagle Ford alone accounted for over USD5 billion, a feat the South Texas shale producer has been unable to accomplish since late 2013. The Eagle Ford’s success is largely attributed to a shift in deal focus to mature, production-heavy assets, signalled by Baytex Energy’s USD2.5 billion acquisition of Ranger Oil Corp, the largest US upstream deal in the first quarter. Other notable deals involved Chesapeake Energy Corp, which totalled about USD2.8 billion for transactions with WildFire Energy I LLC and INEOS Energy. The uptick in M&A activity in the Eagle Ford primarily stems from companies looking to focus more on producing assets, and less on drilling inventory.

Although it was not the top deal-making basin in the first quarter, the Permian remains a featured area for companies seeking undeveloped inventory. Recent acquisitions in this basin, however, may indicate a shift in the future of upstream M&A and companies’ ability to acquire purely undeveloped inventory, given the consolidation of acreage positions within the area. For example, the Permian Basin began the second quarter with Ovintiv’s purchase of three EnCap-backed companies for USD4.275 billion. Following this deal, Tap Rock Resources LLC, Hibernia Energy III LLC, and Civitas Resources announced a deal close in size (USD4.7 billion) on 20 June, with the transaction closing in early August. From this transaction, Civitas will gain 68,000 net acres in the Permian, which is expected to increase its production by 60%. Finally, VTX Energy Partners is expanding its reach in the Permian by seeking to acquire 12,000 net leasehold acres from an undisclosed seller.

While these deals indicate inventory in the Permian is still in high demand, analysts are concluding that there may be fewer opportunities in the Permian Basin moving forward due to the lack of desirable core inventory. Another example pointing to this trend is Chevron’s recent acquisition of PDC Energy for USD6.3 billion. In this transaction, the supermajor acquired PDC to expand its reach in the Permian, which has led analysts to believe that the Permian may have exhausted many of its “best wells” and that purely undeveloped inventory is dwindling. Furthermore, upstream M&A metrics from 2022 support this finding, as 60% of oil deals involved the sale of private companies and their assets to public E&Ps. These recent trends have led analysts to believe that there may not be many remaining private companies looking to sell inventory in the Permian, which will likely drive up competition in the near future.

In the wake of dwindling inventory, companies seem to be pursuing one of two potential paths forward. First, some large, major oil companies are seeking to buy out smaller rivals in the region, as demonstrated by the Chevron and Ovintiv deals. Second, companies will likely turn to the outer edges of the basins to find viable inventory. While these areas are not the “core” of the Permian, some companies view them to be “overlooked” assets with future potential. Nonetheless, both trends indicate that inventory may only become more sparse in the Gulf Coast, and companies will have to think critically about how to acquire inventory in the future.

Another source for deal-making in the Permian comes from the acquisition of mineral interests. Individuals or companies that own the mineral rights to their land receive royalty payments based on the minerals, which include oil and gas, that are extracted from that land. Due to the Permian’s mature development and a more careful focus on the minerals’ ability to provide sustained future cash flows, the value of royalty payments in this area has increased from between USD10,000 and USD20,000 per acre in 2020 to approximately USD40,000 per acre now in certain transactions. A recent Permian mineral interest transaction between Kimbell Royalty Partners LP and Hatch Royalty LLC supports these estimations. In the Kimbell/Hatch Transaction, Kimbell acquired 889 net royalty acres from Hatch’s mineral interests for approximately USD270.7 million, which equates to between USD35,000 and USD40,000 per acre. Therefore, companies can seek to obtain the mineral rights to these areas to entitle themselves to royalty payments in the event that other M&A opportunities are unavailable.

Payout from mineral rights, however, would be based on location, with landowners in the core having the greatest opportunity for a high payout because of the ongoing production of oil wells and continuous extraction of minerals. Landowners in areas where production has slowed or stopped retain an opportunity, but profits will likely not be as high as in areas with current production.

Previewing what may be in store for the rest of the year, activity in the oil and gas industry was unchanged in the second quarter, according to executives responding to the Dallas Fed Energy Survey. Oil and gas production, while still increasing, did so at a slower pace than in the first quarter.

Capital concerns

Similar concerns surround financing acquisitions and operational opportunities within these regions. For the Permian, about two thirds of large private equity companies have left the sector in the last decade. While opportunities still exist for large-scale financing, oil companies need to be increasingly cognisant of every aspect of a transaction, including ESG and related issues, in order to market their companies in a way that is attractive to any source of capital.

One reason for this decline relates to recent interest rate increases. In response to these increases, and with certain equity players leaving the sector, some upstream producers are turning to debt financing for funding cash portions of M&A deals. For example, the largest deal of the first quarter, Baytex’s acquisition of Ranger Oil was partly funded by the issuance of 8.5% senior unsecured notes for the deal’s cash portion. This may become a more attractive option if larger sources of equity remain difficult to access. Nevertheless, while tighter credit conditions from February to June 2023 did not affect the business of most E&Ps and service companies, there are some industry executives who expect a slight impact on business development from uncertain credit conditions through the rest of 2023.

Future equity-based deals, however, may also involve smaller companies and stock-for-stock transactions. For example, family offices are becoming more reliable investors, which may assist in offsetting the withdrawal of larger, institutional investors. Family offices are focused on longer-term investments and are not as concerned with the volatility of oil and gas prices. Moreover, family companies investing in E&P companies that are not backed by private equity firms do not have to pay management or carried interest fees, which allows many of the smaller companies to begin investing more quickly. Analysts project family offices to provide around 12% of capital to E&P companies within the next year, a jump from a 7% projection just six months ago. While small family companies are probably unable to completely fill the gap left by private equity firms, their presence in the oil and gas industry will likely expand moving forward.

Natural gas as an opportunity

Natural gas may provide additional opportunities for deal-making, as certain private E&Ps are aiming to sell in the Haynesville Shale Basin. Many buyers are skeptical, however, following the recent decline of gas-based M&A due to an over 50% drop in gas prices. This drop also caused a delay in constructing wells in the region, but well construction has not fully ceased. Moreover, there is hope that prices will rise due to increased demand in electric power generation, and new wells under development will serve an important role in meeting this demand when prices increase. 

Outside of the Haynesville Shale, natural gas production in Texas is on an upward trend with the reopening of the Freeport LNG facility. After experiencing a fire in June 2022 and awaiting regulatory safety approvals until early March of this year, the plant is back to transporting natural gas at full capacity as of 30 March. The return of Freeport could ease financial stress in this sector, as the facility accounted for 20% of total LNG exports from the United States and generated USD35 billion in revenue between January and September of 2022, including after the facility shut down halfway through this period. With the facility fully operational, analysts predict that the increased export of LNG will assist in spurring more natural gas deals, which have recently slowed due to the low and volatile pricing of natural gas. In fact, the second quarter of 2023 saw slower growth in natural gas production than the first quarter, as commodity prices continued to face headwinds.

Additionally, the Permian Basin, which is known for its success in the oil sector, may see natural gas increase in importance in the near future, especially given the concerns regarding decreasing oil inventory. For example, the basin was projected to reach record levels for both natural gas and oil output in May 2023. To sustain these increasing natural gas levels, however, more infrastructure will probably be necessary.

Operational trends: issues and concerns

As noted above, one point of concern for upstream companies is how to increase capital investment. While companies are determining how to increase financial support, they must also figure out how to minimise expenses in a volatile commodity price environment, given the continued focus on free cash flows generated from operations. Certain gas producers are also showing more resilience to challenging economic conditions. Oil and gas operators reported increasing costs for a tenth consecutive quarter as of the second quarter of 2023. In particular, smaller E&Ps (those companies producing less than 10,000 barrels per day – BBL/d) are under greater pressure from higher drilling and completion costs than the larger E&Ps due to the economies of scale and negotiation power differences. In the past, the industry has been able to implement creative operational solutions in this type of economic environment. One current approach to minimising expenses being used by certain operators, notably in the Permian, is to reduce costs through reusing water. By entering into takeaway agreements to treat produced water for reuse by operators, companies do not have to pay electricity, transportation, or royalty expenses associated with the water. Thus, it is expected companies will continue to review their operational methods in an effort to reduce operating costs and maintain fiscal discipline.

Moreover, increased demand in the Permian, notably for natural gas, may strain existing takeaway capacity. E&P companies could choose to build additional takeaway infrastructure, which would be costly and might require financing for these types of projects. Current E&P infrastructure development is already probably inadequate to handle increased demand without also increasing flaring. Thus, in order to build enough takeaway infrastructure to meet increased demand without flaring, companies will continue to look for solutions with midstream providers in the area. There will also be additional takeaway capacity coming online in the future to partially alleviate this issue. 

Conclusion

While there is some uncertainty regarding the commercial and financial issues affecting the Gulf Coast region, recent trends demonstrate the resilience of the industry, innovative solutions to transactional and operational obstacles, continued significant demand and future growth opportunities within the upstream oil and gas sector for the Gulf Coast region.