SHAWN SIMMONS WAS a middle school student in Houston, Texas, the first time someone encouraged her to consider a career in engineering.
“Our amazing teacher, Ms. Moore, suggested I look into engineering during one of our frequent talks outside classroom instruction,” Simmons wrote in a 2016 article about mentoring for STEAM magazine. “Since I admired and respected Ms. Moore, I listened intently to what she had to say and then and there decided to apply to Booker T. Washington High School for the Engineering Professions, a Houston high school specializing in engineering.”1
Fast forward a couple of decades, and Simmons found herself living and working in Lagos, Nigeria, in her capacity as an environmental and regulatory supervisor for ExxonMobil Development Company.
“I was fortunate enough to be part of the team that launched a woman’s network and its inaugural ‘Introduce a Girl to Engineering and Science Day’ in Nigeria,” wrote Simmons, a petroleum and environmental engineer with a doctorate in environmental toxicology.
These days, Simmons is back in the Houston area, where she continues to encourage girls and mentor women. She returns to Nigeria three or four times a year, however, in her current role as environmental and permitting manager for ExxonMobil’s Gulf Coast Growth Ventures. One of her many responsibilities is to help ExxonMobil remain compliant within Nigeria’s environmental regulations.2
“I’m enjoying Africa and the projects there,” Simmons recently told Diversity/Careers in Engineering & Information Technology. “It’s all so big and exciting, and I like that.”3
You could say Simmons is an ambassador of sorts: For the Nigerians she’s encountered, she’s provided a glimpse of American culture and perspectives while making a positive impact in community members’ lives. At the same time, she has been playing an important role in helping a major oil and gas multinational operate successfully in Nigeria.
That dynamic is a small picture of the positive relationships that American oil and gas professionals—and companies—are realizing throughout the African continent. It’s a picture of mutual respect and cooperation, and it’s something we need to see more of.
I have been so blessed to have worked under great American oilmen who took a keen interest in me and mentored me, including:
Jeff Mitchell, Senior VP and COO, Vanco Energy Company
Gilbert Yougoubare, Vice President of Africa, Vanco Energy Company
Bob Erlich, Partner and Executive Director, Upstream, Cayo Energy LP
Mark Romanchock, now Principal Geologist, Samsara Geosciences
Todd Mullen, Interim CEO, EVP & General Counsel, PanAtlantic Exploration Company
Bill Drennen, President and CEO of WTD Resources, LLC
H. Daniel (Danny) Hogan, General Manager, LUKOIL International Upstream West
Ronald Wallace, exploration and development specialist
Bruce Falkenstein. Manager, License Management – Joint Operations and Compliance, LUKOIL Overseas Offshore
And the irreplaceable Gene van Dyke. A true pioneer and trailblazer.
Even when I went rogue, they always knew how to rein me in and guide me to find my best self. They shaped my thinking about oil and gas. I hope many young Africans will get the privilege to work with men like this. No-nonsense guys, hard to please, who never had a problem with me wearing cowboy boots or being country. They had my back and were always there to support me during the most difficult times.
We need American oil and gas companies to continue operating in African communities and to continue hiring African people, purchasing from African suppliers, and partnering with African companies. And we need companies willing to share knowledge, technology, and best practices, businesses that are willing to be good players and form positive relationships in the areas where they work.
Doing this remains very much in the interest of the American companies. They can reap tremendous financial rewards here.
It’s up to us, as African community members, leaders, and business representatives, to do as much as possible to encourage American oil and gas companies to launch, continue, and grow African operations.
In 2005, U.S. oil production had been in decline for 3 decades and was only totaling about 5.2 mbo/d. Imports, meanwhile, came to about 10.1 mbo/day. The country’s natural gas production had peaked at 22.6 tcf in 1973 and was at 18.1 tcf in 2005. Alarm bells about a pending “natural gas crisis” were sounding.
Enter hydraulic fracturing. For roughly 15 years, Texas oilman George Mitchell had been trying to realize a profit from this process, a decades-old technique also known as “fracking.” It calls for sending a high-pressure injection of water, chemicals, and sand into shale deposits to release trapped oil and gas. In the late ’90s, his company, Mitchell Energy, started seeing success fracking natural gas. Gradually, other companies started following their lead. Fracking, combined with horizontal directional drilling (HDD) and other technologies, was making it possible for producers to access oil and gas resources that once were considered impractical to exploit.4
It was a game-changer. Between 2005 and 2015, U.S. natural gas production grew 50 percent, making the U.S. the world’s largest natural gas producer.5
U.S. crude oil production surged during the same time period, reaching 9.43 mbo/d by 2015. It went on to reach an all-time high of 11 mbo/d by 2018.67
While the U.S. oil and gas industry took a hit around 2014, when oil prices started to plummet, shale oil and gas producers remained resilient. Having surpassed Russia in October 2018 as the world’s largest crude oil producer, the U.S. is now an energy exporter for the first time in 65 years.
While I’m happy for my American friends in the petroleum industry, the shale boom is not necessarily good news for African oil exporters. In the years leading up to the shale boom, the U.S. had been one of three primary markets for African crude petroleum, along with China and India. In fact, American refineries along the East Coast were configured to process West Africa’s sweet Bonny Light, which has particularly good gasoline yields, making it important to the autocentric U.S. However, between 2004 and 2013, the volume of African crude petroleum sent to the U.S. dropped nearly 70 percent. If U.S. oil continues to flood the market, oil exports from Africa to the U.S. may stop altogether. This would cause serious concern for African countries like Angola and Nigeria that rely heavily on oil exports for government revenues. This trend underscores the critical importance of capitalizing on oil and gas revenue, throughout the supply chain, to diversify African countries’ economies.
The shale boom has also affected the presence of American oil and gas companies in Africa: Many major U.S. players, including Hess, Conoco, Anadarko, Apache, Devon, and Pioneer, have exited or drastically reduced their footprint in Africa to become major U.S. shale players. There has been both a pull and push factor for U.S. energy companies retreating from Africa: a combination of increasingly attractive U.S. onshore shale opportunities and the perception of higher risk in Africa. U.S. domestic shale plays are perceived as a huge, proven resource with lower geological and political risk.
Meanwhile, in Africa, exploration success rates have fluctuated, and the great promise from African oilfields like Ghana’s Jubilee hasn’t been fully realized. Several developments, including LNG plants in Angola, Mozambique, and Tanzania and the offshore Egina oilfield in Nigeria, saw large cost overruns and delays. A few countries, including Uganda and Mozambique, introduced capital gains taxes on transactions. There has also been unrest in Libya, which has had an impact on some of the producers there, and South Sudan oil operators have been feeling the pinch of U.S. sanctions. The oil price downturn and bank cutbacks on lending have had a negative impact as well.
U.S. oil companies have a long history in Africa, most notably the two supermajors, ExxonMobil and Chevron. While these players have remained, over the past 5 to 10 years, independent American E&P companies continued to move out of Africa and shift their attention to domestic shale plays. This period also saw a number of U.S. independents and IOCs choosing to allocate capital to locations such as Brazil, Guyana, the U.S. Gulf of Mexico, and Mexico—regions with either more transparent politics, better fiscal terms, higher quality of geology, or better recovery volume per well.
Smaller explorers have also disappeared, either because they had been unsuccessful with exploration or struggled to obtain funding. Examples include Erin Energy (which had changed its name from Camac Energy in 2015) and PanAtlantic (formerly Vanco). On the other hand, VAALCO Energy has continued to push for a play in Africa by hiring Thor Pruckl, executive vice president, international operations. The company, which is focusing on the Etame Marin in Gabon and Block P in Equatorial Guinea, still has a strong appetite for Africa and a knack for good marginal assets. Noble and Marathon are really the only remaining mid-cap U.S. E&Ps with a presence in Africa.
This trend to abandon foreign E&P projects isn’t limited to Africa, though. U.S. companies have pulled out from other regions where they were historically big players, most notably from the North Sea. Conoco, Marathon, Chevron, ExxonMobil, EOG Resources, and Hess have all sold down or out completely over the last few years.
As I mentioned earlier, the common perception is that U.S. shale is less risky and has better economics than an oil and gas development in Africa. However, as with any comparison, it is often not that simple.
Fundamentally, it is more expensive to extract oil from shale than from conventional reservoirs, mostly because you have to stimulate the shale reservoir through fracking to enable oil to flow. Therefore, conventional onshore production from high-quality reservoirs should be more economical to produce. Offshore production is another story, however. The cost of drilling an offshore well is many times that of an onshore well, even including fracking. Clearly, then, the productivity of the well offshore has to be better to be able to match the economics.
This suggests that if U.S. shale was the holy grail, U.S. shale companies should have consistently performed well, especially coming out of the oil price downturn. That was not always the case. Although fundamentally the economics of production are strong in the U.S., shale has been plagued by issues such as bottlenecks from the high level of production as well as some quality issues and disappointments related to the producibility of the plays.
Although U.S. production has seen a resurgence in recent years, not all shale-focused companies have performed well, and investors have taken issue with the lack of cash generation. There has also been increased pressure on executive remuneration and targets, with high general and administrative costs seen at a lot of companies. Since 2007, energy companies have spent $280 billion more than they generated from operations on shale investments, according to one study. A number of companies have gone into bankruptcy but then reemerged. Companies drill their lowest cost/best return prospects first, meaning that they expect a deterioration in the quality of the well results over time as well as a decline in long-term capital efficiency. There also are perceptions that fracking is harmful, uses too much water, contaminates the groundwater, emits carcinogenic chemicals, and causes earthquakes.
There’s no denying that operating in Africa represents a number of very real risks for American companies. We need to be aware of these risks so we’re better positioned to mitigate them (when possible) and better prepared to have honest conversations with American companies interested in operating here.
In general, E&P companies can expect to face geological, fiscal, governmental, operational, economic and political, infrastructure, gas monetization, funding, and service company risks, among others.
Let’s take a closer look at geological risk, which can be broken into the categories of exploration, appraisal, development, and production.
Exploration risk: For shale plays, there is not much in the way of exploration risk: Most of them have already been discovered. Lots of conventional wells have historical data that mitigates risk.
Exploration risk is much more of a factor in newer frontier areas or under-drilled regions—in other words, most of Africa. Comparing the pre-drill chances of success with exploration success rates over the last few years shows that companies, in general, have overstated the chance of success by failing to correctly analyze the pre-drill risk.
Companies also appear to overestimate the chance of finding oil and find gas instead, which is a very different value proposition. With greater investor and industry scrutiny and tighter purse strings, we’d expect success rates to increase as companies only drill their best prospects.
Appraisal risk: Again, appraisal risk is more of an issue for new discoveries rather than for shale plays. And investors tend to focus more on exploration risk than this important area.
There are two issues here:
First, once a discovery has been made, it must be appraised. And that appraisal must be funded. Some companies may not have thought that far ahead. If the size of the discovery calls for drilling, say five test wells, the company immediately is facing a large funding need.
An example of the market response to this was when LEKOIL made a potential discovery of more than 500 mmboe called Ogo in Nigeria. Company stock went down on the day of the announcement because it would need to raise equity for subsequent appraisal.
Second, substantial risk can remain even after the initial discovery. There have been discoveries that appeared commercially viable after the first well, only to end up being questionable after hundreds of millions have been spent. Examples include Paon/Saphir off the coast of Côte d’Ivoire and Chissonga in Angola.
Development risk: This impacts both shale and conventional projects.
In the U.S., the development risk is more likely to be related to bottlenecks and unforeseen cost inflation. Offshore, there have been countless projects over the last decade that have come online later and cost more than expected. Companies may put in contingencies, but in most cases, their development costs still surged far above what they were prepared for.
However, more recent developments have resulted in better performance as companies have realized and addressed some of the issues they’ve come up against in the past, and the service market has loosened. Many more recent developments have actually come onstream ahead of time and below budget.
Production risk: Another underestimated risk is that once a field starts production, it doesn’t produce at the expected rates. Production disappointment is an issue that has plagued offshore developments. The risk is considered lower for shale, but there have been a number of cases where production failed to meet expectations there, too.
According to a Westwood Energy study, half of on stream oil and gas fields are not producing to expectations; about 70 percent of the fields that had only limited appraisal were found to underperform versus the development plan.
There is geological risk with shale too: Production may underwhelm on issues such as rising gas/oil ratios (gas production increases relative to oil production over time) and interference between wells that have been drilled too closely together, meaning less oil is recovered per well. Combined with many areas of potential bottlenecks, increasing costs mean that—despite all the hype surrounding shale—acceptable returns aren’t necessarily being generated, and it appears that a number of shale plays are reaching a plateau in productivity and efficiency gains.
Perhaps more than geological risk, it’s political risk that keeps investors and oil and gas companies away from many African countries. This can include expropriation, civil disorder, revolution, unilateral imposition of new taxes and royalties, imposition of export controls or withdrawing licenses for export or import, exchange control restrictions, and other factors that reduce the value of the oil and gas venture. Investors worry a lot about political risk, which frankly, is one of the most difficult to quantify because it often is a wildcard.
In many countries, there is the risk of a black swan event, such as a coup, completely changing the landscape. That, in turn, could impact a company’s contract—or create the need for a new one. Although companies can take comfort in most contracts being covered under international law, and arbitration being an option, the years it takes to complete arbitration could well wipe out a company’s equity value (such was the case of Houston E&P company Cobalt International Energy Inc. in Angola).8
Companies also face the risk of dealing with a bureaucracy, especially in frontier regions, which often causes things to take much longer than expected, including obtaining official approvals to proceed with projects. Government approval also is needed, in most cases, for a transfer of assets. It was the government veto of an asset sale that prevented ExxonMobil from buying Kosmos’ Ghana assets.
Another risk that has reared its head recently is countries arbitrarily imposing capital gains taxes on asset sales, erasing the company’s ability to profit from the transaction. With a production sharing contract, the terms are set and generally enforceable through international arbitration, so these contracts are rarely broken by host governments. Tax and royalty contracts can be exposed to changes in corporate tax rates.
An area of particular concern for U.S. companies is the risk is getting caught up in corruption issues, either directly or indirectly. The reputational damage and potential fines may mean that companies simply don’t want to take the risk at all, whatever the reward. Several companies operating in Africa, including Cobalt and Weatherford International, have been investigated under the U.S. Foreign Corrupt Practices Act (FCPA).9 U.S.-based Och-Ziff Capital Management Group and two executives settled charges in 2018 related to the use of intermediaries, agents, and business partners to pay bribes to high-level government officials in Africa for energy investments. Och-Ziff agreed to pay $412 million in civil and criminal matters, and CEO Daniel Och agreed to pay $2.2 million to settle charges against him.10 BP was recently the subject of a BBC documentary about “suspicious payments” to the Senegalese president’s brother.11
Other factors that are important to the risk equation are investor sentiment toward a region or country. There may also be specific reasons for investors to be skeptical about a particular country, from recent exploration failures to failed M&A transactions.
The risks for shale production are very different from the challenges faced by a deepwater development. While there is still exploration and appraisal risk, as I said, most of the main U.S. plays have now been discovered, and the focus is more on the delineation and production of existing plays. The cost of appraisal is much lower, which allows companies to reduce the geological risk relative to an offshore play. Production disappointment is a risk but comes from different issues: the risk of interference between wells from too-tight spacing, underestimating decline rates (b-factor), or underestimating the increase in gas/oil ratio over time.
Political risk obviously still exists in the U.S. but is much less of an issue from U.S. investors’ point of view. Spillage is a risk, especially given harsh U.S. penalties, but the risk of a major incident is lower onshore. There are a large number of services and consumables required for shale production, and with a large amount of production concentrated in one area, there is the risk of constraints either inhibiting production or pushing up costs. Areas of concern have included:
Water handling
Natural gas liquids processing capacity
Rig availability
Completion equipment
Sand
People
Encouraged by the master limited partnership (MLP) boom, most companies outsource their midstream requirements, which means that midstream assets trade at much higher multiples. There are two key risks associated with this. First, if companies have committed to take-or-pay agreements in a low-price environment and production is curtailed, they could be stuck with the pipeline fee. Second, companies that make these agreements in a high-price environment could find they can’t get access to pipeline capacity.
Africa holds a vast amount of discovered oil and gas resources. Over the last decade, there has been a phenomenal amount of gas discovered in Mozambique, Tanzania, Senegal, Mauritania, and Egypt.
New oil discoveries have been much harder to come by. There has been a lack of large oil discoveries in West Africa since the Jubilee oil field found in 2007. Jubilee, Ghana’s first commercial oil discovery, initially was estimated to contain 3 bbo representing $400 million in revenue for its first year of production and $1 billion after that. Companies jumped on the bandwagon, with dozens of “Jubilee lookalike” fields being targeted from Morocco down to South Africa. At least 50 wildcat wells have been drilled since that time with the only notable success coming from the SNE Deepwater Oilfield in Senegal (however, ConocoPhillips, the U.S. company involved in this discovery, chose to exit). This is not just an African phenomenon: Exploration success rates, especially for oil, have been very poor over the last five years with a low rate of commercial frontier exploration success and resulting high finding costs.
The SNE project in Senegal has been all about potential. As for returns, they’re still on the horizon.
The oilfield is estimated to hold both oil and natural gas—an estimated 2.7 billion barrels of recoverable oil reserves. However, the actual value creation has been disappointing so far.12
Senegal Hunt Oil obtained the exploration license for SNE in 2005. FAR Limited shot seismic in 2007, and by 2009, $21 million had been spent. Cairn/Conoco farmed in, and the field was discovered in 2014.
By late 2018, Cairn, which has a 40 percent stake in the field, had capitalized the equivalent of $460 million of gross spending; with 2019 capital expenditures, Cairn will have spent $500 million to get to the final investment decision on 200 mmboe net 2C or $2.5 boe (undiscounted). First oil is expected in 2022, and peak production is estimated at 100,000 bbl/d.13
Woodside paid Conoco $430 million for a 35 percent stake in the field in 2016, or around $2.2/bbl based on the 560 mmbbl cited by Woodside at the time. Conoco only made a $138 million gain on the sale. Another way to look at it, assuming an optimistic 1/5 success rate for Conoco’s exploration globally, Conoco will have invested $1.4 billion on exploration for a $138 million gain—only a 10 percent return. However, this was in a low oil price, buyer’s market.14
Nevertheless, integrated operators are realizing they need to replenish inventory, meaning transactions are likely to increase. And exploration success rates should improve as operators are now more capital disciplined and more likely to drill only their best wells.
What’s more, exploration costs have fallen dramatically in the last few years, as the cost of service provision such as rig rates has come down, the efficiency of drilling has improved (higher spec rigs and high grading of crews), and drilling is being conducted in more favorable conditions (e.g., avoiding high pressure, high temperature, or ultra-deepwater plays). Where a few years ago it wasn’t uncommon for an exploration well in Angola to cost more than $250 million, deepwater exploration wells in West Africa being are now being drilled for less than $50 million. For example, Ophir’s Ayame well in Côte d’Ivoire cost $20 million.
It is still possible, based on recent deals/equity market valuations, to buy oil resources at a discount, compared to costs in recent years.
According to Drillinginfo.com, Africa saw 247 exploration wells spudded (initiated) in 2018, representing 19 percent of the year’s worldwide total, the same as the year before.15 However, onshore drilling in Algeria and Egypt accounted for 78 percent of this activity, with Algerian NOC Sonatrach alone spudding 76 wells.
In 2014, 67 deepwater new-field wildcats were spudded offshore Africa, representing 33 percent of the total worldwide. In 2016, however, the number fell to just 12, or 14 percent, figures that held nearly steady in 2017 and 2018.
However, the news is starting to appear more promising: nine deepwater discoveries have been made since the beginning of 2018. These include discoveries by Eni in Angola (Kalimba, Afoxé, and Agogo)16 and by Total in Congo (Ndouma) and offshore South Africa (Brulpadda).17 Also, during this period, according to Westwood Global Energy Group, there were some high-profile failures in West Africa, including Kosmos’ Requin Tigre-1 offshore Mauritania, FAR’s Samo-1 offshore The Gambia, and two probably non-commercial pre-salt discoveries at Boudji-1 (Petronas) and Ivela-1 (Repsol) offshore Gabon.18
Frontier drilling looks set to increase through 2019 and into 2020, and Total is expected to drill its first wells in Mauritania/Senegal, at the Jamm-1 and Yaboy-1 wells offshore Senegal and Mauritania, respectively. Kosmos, carried by BP, will drill the large Orca prospect, which is reported to have 13 tcf in-place potential. Elsewhere on the margin, Svenska is expected to drill the Atum-1 prospect offshore Guinea Bissau, and Eni is expected to continue its exploration campaign in block 15/06 offshore Angola.19
Projections for exploration capital expenditures in Africa are also looking up following a drop of 71 percent between 2014 and 2017, according to Rystad. An initially slow and then robust recovery at a compound annual growth rate (CAGR) of 18 percent over the next 12 years is projected.
African exploration acreage awards have increased significantly in recent years. In 2017, 840,000 square kilometers were awarded, followed by 490,000 square kilometers in 2018, and 340,000 square kilometers as of the first quarter of 2019. That makes Africa the most popular region globally for new acreage among operators.20
Until recently, Angola has been viewed as a relatively unattractive investment destination. Its fiscal terms have been some of the harshest in Africa, and the costs are high due to local content requirements. Exploration in the much-hyped pre-salt basin turned out to be a costly failure, and new developments have stalled. However, reforms by President João Lourenço—intended to increase transparency and make exploration easier—have captured the interest of E&P companies around the globe.
Cameroon is an established, yet underexplored, oil province. The perception is that Cameroon has great potential for natural gas E&P, with more recent exploration for larger oil targets having failed. There has been some offshore exploration over the last five years, but the results have been relatively disappointing and, where successful, generally encountered wet gas.
The Republic of Congo is a mature province, so it doesn’t offer much in the way of exploration potential. However, Eni’s offshore Nene discovery is one of the biggest in West Africa in recent years. Congo is now an established producer of more than 300,000 bbl/d with significant onshore and offshore production. In October 2016, Congo ratified a new hydrocarbons code, overhauling its oil and gas industry.
Ghana is a poster child for successful frontier exploration and development, with current production reaching around 214,000 bbl/d.21 Kosmos Energy discovered commercial quantities of oil and gas in Ghana in 2007. The Jubilee field was developed in less than 3.5 years, reaching first oil in December 2010. Ghana has also successfully developed gas for the domestic market. Although exploration fizzled out during its three-year-long maritime border dispute with Côte d’Ivoire—which was resolved in 201722—there’s plenty of promise. Companies like Tullow and Kosmos still see near field and exploration potential to extend production plateaus and increase reserves, and new companies have come in to explore. Ghana is one of the more stable nations in the region, with a good record of power changing hands peacefully.
Given the large number of unsuccessful wells and the failure to make the Paon discovery work, market sentiment on Côte d’Ivoire’s exploration potential is not favorable. Côte d’Ivoire has a small existing oil industry with about 33,000 bbl/d of production.23 The lack of success from deepwater exploration, represented by a number of non-commercial discoveries, has seen notable players such as Anadarko, African Petroleum, Exxon, Ophir, Lukoil, and Oranto exit. Still, it is encouraging to see recent entries by Eni and BP/Kosmos as well as re-entry by Tullow.
In Mauritania, the country’s tertiary potential had been scarred by the compartmentalized, Miocene-aged Chinguetti discovery, where production has now ceased. Kosmos has had some huge gas discoveries, despite its thesis of finding oil, cementing the market’s view that Mauritania is more of a gas province. Given the amount of gas found so far, further gas is unlikely to be commercialized, so the oil story needs to work to get interest back.
Morocco was viewed as an area with great promise by a number of companies and investors, but following a string of dusters (most recently Eni/Chariot), with little encouragement, interest levels have fallen, and many companies have exited. Morocco still has some of the world’s best fiscal terms. The potential of a domestic gas market or easily getting gas to Europe are the key positives. There are diverse play types, including offshore Cretaceous fan, Jurassic carbonates, and U.S. Gulf of Mexico-type salt diapir plays.
Nigeria is Africa’s largest oil producer. The inability of the Nigerian government to pass a new hydrocarbon law and the resulting regulatory uncertainty continues to hold back investment in new capital-intensive development projects and has reduced the appetite for deepwater exploration. Other issues are disruption to pipelines/bunkering, state operator delays and inefficiency, delays in liftings/payments, and partner risk. Onshore and offshore exploration efforts in Nigeria have been directed towards the tertiary Niger-Delta petroleum system.
Although the dry holes a few years ago have tarnished Namibia from an investor standpoint, it was interesting to see some previous Namibian skeptics (lack of proven source, reservoirs, and traps; plus those that thought it was a gas province) taking an interest in exploring there. In April 2019, ExxonMobil announced plans to increase its exploration acreage there. Namibia has a good operating environment and existing infrastructure (deepwater port/logistics hub) at Walvis Bay. Along with its long-established regulatory regime set in a politically stable environment, Namibia’s legal framework and oil and gas code, in general, are considered to be investor-friendly. There have only been about 15 wells drilled to date. It has an attractive fiscal regime.
Senegal has been a rare positive exploration story over the last few years, given the SNE and Tortue discoveries, which should be online in the early 2020s. Senegal joined the Extractive Industries Transparency Initiative (EITI) in 2013. The Petroleum Code was reformed in 2016 to support transparent development of the oil and gas industry, and Senegal unveiled a new petroleum code in 2019. It is one of West Africa’s more politically and economically stable countries, and it has had a functioning democracy since its independence from France in 1960. President Macky Sall, a geologist and geophysicist, came to power in 2012 and won another five-year term in 2019. Senegal has a fairly attractive production sharing contract-based fiscal regime.
Fiscal terms have a significant impact on the economics of a development. The type of contract that companies opt for is important. Let’s look at production sharing contracts compared to tax and royalty contracts.
Production sharing contracts:
Generally, are less sensitive to capital expenditures and oil prices than tax and royalty contracts.
U.S. fiscal terms are attractive, but royalties can be high.
Tax terms will vary by country.
The terms are generally enforceable through international arbitration; contracts are rarely broken by host governments.
To look at the impact of fiscal terms on deepwater developments in Africa, we can use the assumptions above and only vary the fiscal terms to see how the countries stack up from a profitability standpoint.
For example, let’s say a company is developing a 500 mboe field (90 percent oil) in West Africa at $60/bbl Brent, with an adjustment of $10/boe for capital expenditures and $10/boe for operating expenses. We have compared this scenario to a similarly sized U.S. shale oil development in the prolific Permian Basin. The Permian Basin is considered a major driver of U.S. (and North American) upstream and midstream profits.
Although it is the same size, the Permian Basin development likely has less oil than the African site, and we assumed a $7/boe adjustment for capital expenditures and an $8/boe adjustment for operating expenses.
On an un-risked basis, the net present value per barrel available from a West African deepwater development is better than a U.S. shale project.
Put another way, if there were no difference in risk, a company would be more likely to invest in a West African deepwater project than a U.S. shale project.
The realized value is higher in West Africa because, in the U.S., the amount of crude produced is lower (there are more gas and natural gas liquids associated with shale). The African project also gets a bigger discount (based on the supply of crude oil from shale), even though we assume that the gas has zero value in West Africa for the purposes of this comparison. Operating costs are slightly lower in the Permian, as are development costs—although many more wells are required. The total cash flow on an undiscounted basis is much higher in West Africa, but also further out, which is why the higher the discount rate, the more punitive it is on deepwater. The government’s take is slightly lower for an average West African development, as we assume a 32.5 percent royalty off the top in the Permian. The break-even oil price at the wellhead is similar for both, but given the $8/bbl discount realized that we assume for the Permian, the break-even is higher.
There have been many deepwater developments that have taken over five years to progress from final investment decision to first oil. However, companies are now opting for simpler, cheaper offshore oilfield designs, which are quicker to implement than bespoke solutions and more cost-effective. Companies also have the option of breaking their investment into phases, so that later phases can be funded out of cash flow and be de-risked by previous phases. Shortening the development cycle by one year reduces break-even prices by 10 percent on average.
One of the most significant perceived advantages that a shale development has over a deepwater development is that the pace of development can be altered to suit the commodity price environment. In theory, rigs can be added and removed in a matter of months (but this can pose logistical and cost challenges). However, the ability to reduce capital expenditures to match cash flow is only of some value to companies that need a return on the huge amounts they paid for acreage in the first place.
The quality of the resource is still a major factor in determining costs. Development costs have come down through a combination of lower service costs, simpler/phased developments, and standardization. Cost inflation is unlikely to rear its head soon offshore, but we did see some in U.S. onshore.
At $60/bbl Brent, the price realization per boe from a standard West African offshore development is around 30 percent higher than from a U.S. shale oil development. Historically, heavier crudes traded at a wide discount, but given rising U.S. light supply (WTI) and declining heavy (from such sources as Venezuela and Mexico), U.S. crude may continue to trade at a discount. The revenue per boe is much higher for an average offshore development, even compared to U.S. shale plays with high outputs of oil, such as those in the Permian and Bakken Formation.
Let’s assume a $60/bbl Brent price with a $5/bbl Brent-WTI spread, a $3/per thousand cubic feet (mcf) Henry Hub (HH) price and natural gas liquids trading at 35 percent of WTI (i.e., $19/bbl). For a shale development that is approximately 70 percent black oil, the realization per boe is only $42/boe.
An offshore development in Africa, meanwhile, would realize $54/boe if we assume it was 90 percent oil, and all the gas produced was re-injected or produced for free. Crude pricing depends on the quality of the crude (e.g., API/sulfur), but location is important, too—and in general, West Africa crudes of similar quality trade close to Brent or at a premium.
In the U.S., given the relative oversupply of WTI, it trades at a discount to Brent despite being of a higher quality. There are further in-basin differentials, which is the cost of getting the crude to the WTI delivery point at Cushing. Most shale plays have a large amount of natural gas liquids/condensate, for which pricing is very weak in the U.S. (roughly 35 percent of WTI), as there is an oversupply, and in many cases, ethane is “rejected” and sold as natural gas instead. Gas pricing in the U.S. is also relatively weak (around $3/MMBtu) and unlikely to go much higher in the future, given the large amount of associated gas that can be produced, almost regardless of price, and the economic incentive to produce is coming all from oil.
In West Africa, gas monetization varies by country—and even by regions within a country. In most cases, the discovery of gas is viewed as a hindrance rather than a positive. The various options are generally flaring, re-injection, production to shore either into a gas grid or dedicated facility (power plant/petrochemical facility), into onshore LNG or floating LNG.
The ability to obtain funding for offshore developments outside the U.S. is harder and more expensive than for U.S. onshore companies, given the perceived higher level of risk and the higher liquidity in the U.S. market. The source of funds for many companies came from private equity over the last few years, but with it comes the expectation of high returns (about 20 percent), making funding projects more expensive. Sustained higher oil prices should bring the cost of funding down and open up equity markets again.
Over the last few years, it has been hard for companies to get farm-outs executed for pre-FID discovered resources, and the deals that have been done were generally at low prices and certainly at a discount to fair value. Asset liquidity is much lower outside the U.S.: A smaller pool of buyers means that companies operating in Africa often have to accept less than fair value. Although the U.S. has a much bigger liquidity pool to draw on for raising both debt and equity, the market has been reluctant over the last year to fund oil companies, so there have been very few equity raises or IPOs to force the companies to live within cash flow.
I’ve presented a frank look at the risks American companies face, both in Africa and in the U.S.
But those risks do not negate the opportunities that Africa offers for American companies to earn significant returns on their investments.
The factors that help determine a return can be categorized into three basic elements:
The cost of getting hold of an asset (oil and gas mineral rights, oilfield license, etc.).
The revenue obtainable from the oil and gas produced.
The cost of production.
In terms of these elements, African assets have an advantage over U.S. assets. That’s because it’s generally cheaper to obtain assets in Africa. Plus, the revenue that can be obtained from the assets, in many cases, is higher, and the cost of production (in costs and taxes), in many cases, is cheaper.
There are costs associated with getting access to an asset, which is an important and often-overlooked component of its valuation. In the U.S., to be able to get hold of an asset or resource, you will have to pay full price, given a large buyer universe. Resources in Africa can generally be obtained for less than fair value, certainly in the current market, which is largely because of lack of buyers and a much less competitive market than the U.S. (although risk, of course, plays a part).
The revenue generation from an asset is determined by whether it is primarily oil or gas. Oil is much easier to monetize, given the ease of transportation and a liquid global market. Oil assets in Africa generally will generate a significantly higher price than the equivalent oil in the U.S., as the U.S. is suffering from logistical constraints and oversupply of shale oil.
Therefore, there is the potential to realize a 10 to 15 percent higher price from oil produced in Africa—which could result in a big difference in a company’s return.
Gas is more difficult to monetize and is dependent on the location and market. There is the potential in Africa to realize better prices for gas than in the U.S., where, again, oversupply keeps a lid on pricing (less than $3/MMBtu). In Africa, there is the possibility in many countries to use gas to replace existing higher-cost fuel, such as diesel, for power generation, and another route to market is through LNG.
The cost of production involves the cost to bring the asset online (capital expenditure), the cost to operate the asset (known as operating costs or lifting costs), and the tax payable (royalties, taxes, etc.). The costs are largely dependent on the type of asset and geology. Some of the Nigerian onshore oil plays, for example, have a very low cost per barrel relative to the U.S., due to the lower costs associated with onshore production, the prolific nature of the wells, and a lower transportation cost. Tax rates vary dramatically across Africa and even vary within a country. There are several countries with very favorable tax terms, which unsurprisingly are the countries with little or no oil production, such as South Africa and Morocco.
Around five years ago, if a company made a discovery, the market would not only give the company credit for the discovery but would also give credit for the other identified, analogous prospects that would have been de-risked (Tullow is a good example of this). This is perfectly valid, and if exploration comes back into vogue, we should see it happening once again. However, the reason that the market stopped ascribing future value was that the E&P companies promised a number of follow-on discoveries (“Jubilee lookalikes”) that never materialized (e.g., Anadarko’s so-called “string of pearls” of expected discoveries up and down the Gulf of Guinea coast). In order to benefit fully from this, companies need to have blocked up a large amount of contiguous acreage, which is much easier to do in frontier regions.
Of course, honestly acknowledging our risks is one thing. It’s also vitally important to minimize them as much as possible. Andrew Skipper, head of Hogan Lovells’ African practice, summed it up nicely in a 2018 article in African Law & Business.
“We know the need for government to work with private sector in Africa to attract more foreign direct investment (FDI). We know that to do that, we need to create policy and regulate consistently in a modern way (for example, to deal with the growing number of fintech and entrepreneurial start-ups). There also needs to be a focus on building and strengthening institutions, eliminating corruption, and becoming a more transparent and educated nation.”24
These factors—transparency, stability, and good governance in particular—are of great importance to U.S. companies. An American friend and long-time industry exec with vast experience in Africa once told me that he would happily pass on a million-dollar oil field if he felt the local government was unstable or unreliable. Government stability, he has found, plays a huge role in determining whether a county is likely to honor contracts if and when new leaders take power.
Basically, African governments that want to foster American oil and gas activity need to look at their country from the perspective of American investors. When companies do their due diligence, what are they going to find? Does the government have a demonstrated track record of stability? Of honoring foreign contracts? American companies have plenty of other investment destinations around the world and in their own backyard. To compete for those investments, governments need to ensure that their fiscal terms are attractive and contract sanctity is strong.
A few other points:
Risk sharing is another way to incentivize investment. Look at Norway’s model of paying for almost 80 percent of exploration costs.
Also important, and often overlooked, is the ease of operating and investing in African countries. Even if fiscal terms are good, fighting through excessive government red tape and approval processes puts companies off.
The ability to transfer assets is important, too. Companies want to know they’ll be able to monetize their assets in the future without capital gains taxes.
Countries that have put the right framework in place need to actively market their country as an investment destination and specify why their oil and gas sector is an attractive place to invest. Countries such as Equatorial Guinea have done a good job of getting the word out about what they have available.
Of course, some factors are outside of governments’ control. They need catalysts to be positive. Catalysts include higher oil prices (which have already materialized at the time of this writing), some major exploration successes, and a return of some M&A activity. For example, major exploration success in Guyana has led to more investment in the country and surrounding acreage. Discoveries have been made by ExxonMobil and Hess, and now other North American companies, including Kosmos, Apache, Eco Atlantic Oil & Gas, JHI Associates, and CGX Energy, are looking to invest there.
During the U.S.-Africa Business Forum in 2014, President Barack Obama made a case for the United States to develop strong economic ties to Africa. Fostering those connections, he maintained, would be good for all involved.
“We don’t look to Africa simply for its natural resources; we recognize Africa for its greatest resource, which is its people and its talents and their potential,” Obama told the African leaders gathered. “We don’t simply want to extract minerals from the ground for our growth; we want to build genuine partnerships that create jobs and opportunity for all our peoples and that unleash the next era of African growth.”25
Among the initiatives described by Obama during the Washington, D.C.-based forum was his “Doing Business in Africa” campaign to promote American exports in Africa, and the Power Africa initiative to help bring electricity to more Africans.
Under President Trump, there is Africa enthusiasm in his Assistant Secretary of State for African Affairs, Tibor Nagy, who has served in Ethiopia, Guinea, Nigeria, Cameroon, Togo, Zambia, and the Seychelles during his 32 years as a diplomat. Nagy is known for being a champion of American values and has pushed to build partnerships that promote better health, jobs, skills, education, opportunity, and security with Africa.
During a speech at the University of the Witwatersrand in Johannesburg in June 2019, Nagy announced the recently passed BUILD Act, which doubles the U.S. government’s investment capital from $29 billion to $60 billion and will enable Washington’s ability to make equity investments in African companies.
Washington also has unveiled the “Prosper Africa” Initiative to increase two-way trade and investment between America and Africa, Nagy said. “Prosper Africa will help us expand the number of commercial deals between U.S. and African counterparts and promote better business climates and financial markets on the continent.”26
As of this writing, Washington continues to support the Africa-related initiatives established by the George W. Bush and Obama administrations. That includes Power Africa, Feed the Future, and PEPFAR, the successful U.S. initiative to fight HIV/AIDS.
It would be fair to say that Washington today is more focused than ever on policies that “put America first.” But we are seeing signs that American leaders, political and military, still understand that fostering good relations with Africa is very much in the interest of the United States. Having good relations with African countries promotes American security. Economic ties with African countries contribute to economic growth in the U.S.
I believe the effort to strengthen, and fully harness, Africa’s petroleum resources will span many years, and we will see many leaders and political stances guide America’s actions. As Africans, it would be wise to encourage and welcome positive engagements as much as possible while, as Washington does, remaining mindful of the needs of and best decisions for our countries.
Africa is a potential energy powerhouse, to be sure—but many parts of the continent lack the infrastructure and resources necessary to capitalize on that potential. Through game-changing partnerships with U.S. companies, we can address Africa’s power issues and do truly amazing things.
Here are just a few examples of what can happen when African energy and American ingenuity join forces:
Denver-based Pioneer Energy is working on solutions to help curb gas flaring in Nigeria and Equatorial Guinea. These efforts have largely been spearheaded by Ann Norman, Pioneer’s General Manager, sub-Saharan Africa. Norman has been a champion of Africa’s energy sector, and she has actually moved to Nigeria to play a more active role in the country’s energy industry.27
In June 2019, two U.S.-based companies, New York’s Symbion Power and California’s Natel Energy, announced a collaboration that would bring hydroelectric power to underserved African communities. Symbion Power is also investing in a Kenyan geothermal plant.28
In addition, programs like the U.S. government-sponsored “Power Africa” initiative encourage private-sector companies to help develop African energy, build up Africa’s power grid, and improve infrastructure in rural African communities. Here are just a few of the many participants:
Citi, a U.S.-based, global financial institution, has pledged to provide capital, industry expertise and advising, and even payment systems to make it easier to do business in Africa.
General Electric “intends to provide technology based on a variety of fuel sources as appropriate for each project, including solar, wind, and natural gas, to deliver the power, and support partners in arranging financing for these projects.”
The United States Energy Association is promoting the growth of the African energy industry by sponsoring events and promoting trade and investment opportunities for U.S. companies interested in African energy.
U.S.-based alternative energy companies such as NextGen Solar, dVentus Technologies, and NOVI Energy are working to develop sustainable energy in Africa.29