If there is one reason why oil companies around the globe have failed to end routine flaring and venting it is because capturing associated gas has been largely a money-losing exercise.
But the times—along with gas prices—have changed and this long-established industry truism is now more of an exception than it is a rule.
This is the chief takeaway from a new report from S&P Global which found that methane- capturing projects launching next year are in some cases set to be more than twice as profitable as those that started before global gas prices spiked late last year.
At the same time, oil companies in the US and beyond are facing mounting scrutiny over methane emissions as data from aerial surveys and satellites have made it easier than ever to independently assess upstream sources of the potent greenhouse gas.
The S&P report focuses mostly on major producing nations in North America, Africa, and Asia where it is believed operators could profitably capture more than 70% of the associated gas that is burned off and vented.
The size of this potential new gas supply tops 80 Bcm (2.8 Tcf), about half of which S&P said could be brought to global markets within the next 2 or 3 years. The firm highlights that capturing this sum of 40 Bcm would result in an emissions abatement equal to about 750 mtpa CO2, roughly the total annual emissions of Germany.
S&P found the biggest opportunity by far is in North America. Last year, operators in the US, Canada, and Mexico combined for a total of 52 Bcm of methane flared, vented, or otherwise lost as fugitive emissions.
At a distant second, the North African countries of Algeria and Libya saw a total of 21 Bcm of associated gas either flared or vented last year. S&P based its findings in part on methane emissions data collected by the International Energy Agency and satellite imagery of flaring activity taken by the environmental nonprofit SkyTruth.
Compared with capturing projects launched just over a year ago, S&P estimates projects starting up in 2023 stand to reap a revenue increase of 140–240% on a 10-year basis. The projection comes as prices for the US benchmark, Henry Hub natural gas, have nearly doubled year-over-year to this week's $7.20/MMbtu.
But as time goes on and prices relax, the upside over the 2021 baseline shrinks, which means that “the strongest incentives are for acting sooner rather than later when it comes to bringing new projects online,” said Eleonor Kramarz, vice president of energy transition for S&P.
S&P forecasts 10-year revenues for capturing projects launched in 2026 will be 56–93% higher than projects started prior to the spike. For projects that start in 2030, the range drops to between 31–38%.
S&P did not include in its analysis Venezuela, Iran, and Russia, each major sources of flaring but also countries that are under economic sanctions that would hamper their ability to bring more associated gas to market.
Not Easy Money
As attractive as they may be, S&P points out that its revenue figures belie the fact that scaling up methane capturing will not be a straightforward exercise for most regions covered in its analysis.
The company identified obstacles that include export capacity, access to capital, commercial/financing environment, and security risks.
In North America there is a general lack of incentives to funnel captured gas into pipelines. Raising new capital for such projects is also a problem for small operators in the US and Canada as well as Mexico’s financially beleaguered Pemex.
Access to capital was found by S&P to be a challenge facing operators in nearly every region it analyzed.
This is also the case for Libya, which in addition to needing more funding, is also facing a prolonged period of political violence and instability that has directly impacted its upstream industry in recent years.
In Nigeria, where 2021 methane emissions were 10 Bcm, access to capital is also a challenge. But beyond that, the state of the nation’s gas infrastructure is described by S&P as “insufficient and unreliable due to security threats and lack of investment.”
S&P suggests government loan programs and international development financing as some of the ways that oil companies can overcome the challenge of finding funding for new capture projects.
The firm also lists several approaches and technologies that could help reduce flaring, which is the number one method used to dispose of associated gas.
These include small-scale liquefied natural gas and compressed natural gas plants for isolated production locations in Nigeria and Libya. In North America and Southeast Asia, it may be more economic and practical to simply expand gas pipeline networks to connect fields with export hubs.
Leveraging associated gas for electrification (to be used locally or tied into the grid) is yet another option the report suggests operators consider.
One recent success story on this front comes from BP’s US shale subsidiary, BPX Energy, which is using associated gas to electrify its oil and gas fields in the Delaware Basin. This initiative saw BPX reduce its flaring rate from 16% of the gas it produces there to less than 1% over the past 4 years.
