Companies in the energy sector and the broader market experienced an interesting year showing steady and strong growth in Q1-Q3 and met volatility in Q4, which effectively erased gains on the year and even resulted in negative returns. The oilfield services (OFS) sector, in particular, was impacted heavily during last quarter’s downturn driven primarily by fears of oversupply in the market and E&P companies cutting back and looking for discounts.
Q4 2018 was truly a dramatic quarter for the industry. It marked the end of the two and a half-year oil price recovery that began in 2016, while natural gas prices reached their highest point since 2014. With ongoing oversupply concerns, stabilizing geopolitical tensions, and lower forecasts for global oil demand, it appears in 2019 oil prices have a long way to recover to its previous high in 2018.
As the calendar turns to 2019, we turn our attention to the Appalachia region, and not by coincidence. Cooler temperatures in the winter months tend to lead to increased natural gas prices and consumption, and the Appalachia region is the largest natural gas producer in the country. Fourth quarter energy prices have moved in opposite directions, with crude prices declining steadily over the period while natural gas prices increased from about $3.0 to $3.5 per Mcf, peaking at over $4.8 in mid-November.
Falling oil prices have a downward pull on operator and mineral values, but they are not the only contributor. There are a host of potential operational issues that can reign in production, cash flow, investor expectations and, ultimately, valuations.
The domestic natural gas market has benefitted from large expansion in recent years, and this can be largely attributed to the growth experienced in Appalachia. Despite the continued growth, transaction activity in the Marcellus-Utica in 2018 was slower than in 2017. Some companies have been moving in to capitalize on the increased demand for natural gas while others are restructuring their balance sheets in order to focus primarily on higher margin assets, such as oil.
There are many reasons that you may want to sell your oil and gas royalty interest, but a lack of knowledge regarding the worth of your royalty interest could be very costly. Whether an inflow of cash would help you make ends meet or finance a large purchase; you no longer want to deal with the administrative paperwork or accounting cost of reconciling monthly revenue payments; or you would prefer to diversify your portfolio or move your investments to a less volatile industry, understanding how royalty interests are valued will ensure that you maximize the value.
One of the most complex aspects of oil and gas valuation is accounting for the risk associated with PDNP reserves, PUD reserves, and the less certain probables and possibles (P2 and P3 Reserves). Generally, there are three ways to account for this additional risk: (1) Using a risk-adjusted discount rate, (2) applying a reserve adjustment factor (RAF), or (3) utilizing a modified option pricing model.
Executing a successful joint venture requires a number of items working in harmony such as solid due diligence, good location, cooperation between both firms, and a degree of luck on the bet they are making.
It seems a bit contradictory that a large amount of projects are structured as joint ventures if they have such a high failure rate. This begs the question, does the success of the JV hinge on the quality of the oilfield or the technical ability of the operator? The answer, we think, lies somewhere in the middle.
Where many producers are struggling to transport their product to market, companies operating in the Haynesville Shale are uniquely positioned to take advantage of the Gulf Coast LNG export resurgence.
Improvements in technology have driven the shale revolution. Among these improvements are both cost cutting by oilfield service providers and longer laterals from E&P companies. While capacity constraints from a lack of infrastructure has led to pricing differentials (particularly in the Permian Basin), a lack of inventory in the global oil market is expected to support higher prices, while also increasing price volatility.
As we plan to do every quarter, we take a look at some of the earnings commentary of large players in the oil and gas space to gain further insight into the challenges and opportunities developing in the industry.
David Harkins recently attended the 38th Annual National Association of Royalty Owners (NARO) National Convention in Denver, Colorado. Many topics were discussed, some of which could have their own blog posts devoted to them; however, this post includes four key takeaways from the conference.
The emerging field of royalty-focused MLPs and mineral aggregation has the potential to provide growth through acquisitions, as well as distribution payments that public investors desire. Kimbell’s acquisition of Haymaker is a good example of this.
Before mid-2014, few investors took notice of efficiency-oriented metrics, instead focusing on stories of new oil discoveries and the development of new wells and new technologies. Since the crash in oil prices, a new measure of success was brought to the forefront: breakeven prices.
As more companies present this metric and more investors rely on it as an indication of performance, it becomes increasingly important to understand what it actually measures, and if breakeven prices can be compared consistently from company to company.
Upstream producers’ stock performance has been volatile, infrastructure issues are lurking and the industry ended the quarter a notch above flat. However, the strategic acquisitions by BP and Diamondback Energy highlight the segment’s continued optimism.
Private equity companies in the energy sector are positioned for an interesting opportunity. These companies have seen a surge of fundraising in recent years, leaving managers with large cash reserves or “dry powder” to be appropriately deployed. Despite the large amount of cash available, these firms are having trouble finding places to invest resulting in a decline in PE activity in 2016-2018 with deal counts dropping for the second year in a row by 8%. However, investments could see a marked increase in energy in the last quarter of 2018 and into 2019 as there is a climate of high demand for return on investment and low supply of cash needed for capital expenditures in upstream oil companies.
This blog post summarizes our whitepaper that provides an informative overview regarding the valuation of mineral royalty interests within the oil and gas industry. While there are a myriad of factors (mostly out of a royalty holder’s control) impacting the economics of a royalty interest, this blog post focuses on valuation methodology.
Companies that have maintained a presence in the Bakken since the downturn in oil prices are beginning to reap the rewards of their patience. Rising oil prices have begat increases in production, and efficiencies gained in recent years have led to higher margins and increased production. As noted in last week’s post about transaction activity in the region, while the Permian Basin has received much of the attention recently, the Bakken certainly appears to be back in business.
Over the past year, followers of the oil and gas industry have taken note of the multitude of transactions occurring in the Permian Basin with large deal values and hefty multiples. But the price differential between WTI and other benchmarks has grown over the last few months, and some attention has moved from the Permian to other domestic shale plays. The activity in other regions such as the Bakken was at one point slow (when compared to the Permian) causing the recent increase in production and the swapping of acreage to fly under the radar while many were focused on Texas.
The oilfield service sector has recovered significantly since the crash in oil prices in mid-2014. As capex budgets have expanded, especially in the Permian Basin, demand for oilfield services such as drilling and pumping has increased. But what does this mean for transaction activity in the sector?
Higher oil prices, coupled with lower breakeven costs for producers, are making drillers, completers and a host of other servicers busier than a gopher on a golf course. Does that translate into higher valuations?
Based upon the content in this blog, representatives from Forbes.com reached out to Bryce Erickson, ASA, MRICS with an invitation to become a contributor to Forbes.com in their Energy section.
In a recent post, we explored the ins and outs of MV Oil Trust. We analyzed the underlying net profit interests it holds, the underlying properties of the trust, and the rights of unitholders including their rights during termination of the trust. This week, we will look into how these play into the composition of the MV Oil Trust’s stock price, and the balance struck between investor’s current return in the form of dividends and potential for returns from capital appreciation.
On April 30, 2018, Marathon Petroleum announced its acquisition of the newly formed Andeavor making Marathon the largest refiner in the U.S. (by capacity) and one of the top five refiners in the world. The merger is moving into its final stages, and Marathon’s CEO is positive about the combination of the two well situated companies. In this post, we analyze the recent acquisition history of Western Refining, Tesoro, and Marathon, which has started to look somewhat like nesting dolls of acquisitions.
In previous posts, we have discussed the relationship between public royalty trusts and their market pricing implications to royalty owners. Many publicly traded trusts have a fixed number of wells, so the value comes from declining distributions. Some of the trusts have wells that have not been drilled, which represent upside potential for investors. In this post, we will explore the subject characteristics of MV Oil Trust. This will serve as a primer for a subsequent post in which we will look further into the composition of its stock price in order to better understand investors’ ability to achieve returns through distributions and capital appreciation.
