Kolibri Global Energy — Playing its cards right

Kolibri is a junior unconventional exploration and production company operating in the Tishomingo oil field in southern Oklahoma. Following the sale of its rights to the Woodford shale to Exxon Mobil in 2013 for US$147m, the company has been focusing on developing its portion of the shallower Caney shale, increasing its total gross reserves to 77mmboe as of December 2022, with the share of undeveloped proved reserves at 82%. Unlike many other shale reservoirs in the area, Caney has a high share of oil in its production, which, coupled with low operating costs, allows the company to take full advantage of favourable oil prices. Kolibri is listed on both TSX (KEI) and Nasdaq (KGEI) and is run by an experienced management team, whose strategy is to grow production, capitalising on KEI’s large undeveloped reserve base and strong well level economics.

Following several years of no drilling due to COVID-19 induced economic and oil price collapse, Kolibri has recently been ramping up its drilling activity, with five wells completed in FY22 and eight wells scheduled for completion in FY23. As a result, the company has enjoyed a significant improvement in operating and financial performance, with average production of 2,780boepd for the first nine months of FY23 (9M23), up 78% y-o-y, and EBITDA of US$29m, +35% (Edison definition). KEI benefits from a low-cost business model, which results in superior operating netbacks (9M23: US$41/boe, including commodity contracts, vs US$62/boe basket price) compared to peers and low operating leverage (see pages 8/9), making the company a fast growing, yet defensive play on the junior shale sector. We expect KEI’s robust drilling momentum to continue into FY24, driving further earnings growth, and forecast EBITDA improving to US$73m in FY24e (FY23e US$42m) based on our expectations of eight well completions and a US$80/bbl WTI oil price. We expect KEI to become free cash flow positive in FY24 and net cash positive in FY25, putting it in a strong position to start returning cash to shareholders or further accelerate its development.

Our approach to valuing Kolibri is based on a discounted cash flow (DCF) analysis. We have made detailed assumptions regarding the company’s future drilling activity, estimating the number of wells to be drilled on an annual basis and certain well economics over the life of the company’s gross proved reserves adjusted for well spacing. To the net present value (NPV) of the company’s gross proved reserves we add the risked valuation of its probable and possible reserves, using the peer group EV/Reserves (gross) multiple of US$3.0/boe. This gives a combined valuation of US$7.5/share (C$10.1/share), at a 10% discount rate and our long-term WTI oil price of US$70/bbl. Given the oily nature of the Caney shale, the key risk, both upside and downside, to our valuation is the oil price. A US$10/bbl reduction in the long-term oil price assumption reduces our valuation to US$6.2/share, while a US$10/bbl increase boosts it to US$8.5/share. Despite an impressive growth profile, due to the low operating leverage, Kolibri can at the same time be viewed as a defensive play compared to the majority of its selected peers, which bodes well for the company should the oil price environment continue to deteriorate.

Key risks attached to Kolibri are the commodity price performance, oil in particular, changes in environmental regulations in Oklahoma and the global decarbonisation trends. While we covered the oil price sensitivity above, we note that, while strict, the fracking regulations in Oklahoma are favourable to oil and gas development.

KEI is a junior oil and gas E&P company, focusing on the shale development in the Tishomingo field in southern Oklahoma. In April 2013, the company sold its rights to the Woodford shale to Exxon Mobil for US$147m, retaining the ownership of the Caney and Upper Sycamore formations. The company has subsequently changed its name from BNK Petroleum to Kolibri Global Energy. KEI is listed on the TSX stock exchange and has recently uplisted on Nasdaq. As of December 2022, the company had 77mmboe in total gross reserves, with the share of undeveloped gross proved reserves at 82%, capable of supporting more than 50 wells. Having guided eight well completions in FY23 (with five wells completed to date), we expect Kolibri to main its drilling momentum into FY24, capitalising on its significant undeveloped reserves and attractive cost positioning.

Kolibri owns working interests in approximately 17,163 net acres of shale oil acreage in the Caney/Upper Sycamore formations of the Tishomingo oil field in Oklahoma. The Tishomingo field is part of the broader Ardmore basin, which belongs to the so-called SCOOP (South Central Oklahoma Oil Province) unconventional oil and gas play. The latter was introduced by Continental Resources in October 2012. Oil and gas development in SCOOP initially focused on the Devonian to Mississippian-aged prolific Upper and Lower Woodford shale, with the later expansion into the Springer shale. Continental estimated at the time that there could be more than 60 different shale formations in the area. Some of the known formations within the SCOOP play are shown in Exhibit 2 below. Established oil and gas companies present in SCOOP include Exxon Mobil, Continental Resources, OVINTIV and Citizen Energy. Kolibri’s acreage is located in Carter and Johnston counties where Exxon Mobil has a significant presence (Exhibit 1).

Following the sale of its rights in the Woodford and other formations in the Tishomingo field in April 2013, Kolibri (then BNK Petroleum) retained its interests in the Caney/Upper Sycamore formations, earning the right to ‘hold by production’ in over 96% of its acreage through historical drilling and participation in the Woodford shale.

Caney is a late Mississippian age shale and is present across several basins in Oklahoma, Ardmore in particular. It is believed1 that stratigraphically it correlates with the well-known Barnett shale (tight gas) in northern Texas and Fayetteville shale (tight gas) in northeastern Oklahoma. In 2002–10, Barnett, arguably the oldest shale play in the US, was the most productive source of shale gas in the US and is now the third largest. The Fayetteville shale within the Arkoma basin that spans Arkansas and Oklahoma (in the so-called STACK – Sooner Trend (oil field), Anadarko (basin), Canadian and Kingfisher (counties)) began in 2004 and at some point has been recognised as one of the 10 largest natural gas fields in the US. As is the case with many other shale formations, Woodford in particular, Caney started as a gas play in the Arkoma Basin in eastern Oklahoma. However early well completions yielded relatively poor results with low initial production (IP) rates. More recent drilling (from 2012) in southern Oklahoma has been more successful, as evidenced by Kolibri’s own drilling results (Exhibit 3). We note that all Caney oil wells are in southern Oklahoma where Kolibri operates.

In the table below we show some of the parameters of the selected wells drilled and completed by Kolibri following its Woodford sale (note: the company did not drill any wells in 2015–16 and 2019–21 due to ultra-low oil prices). The vast majority of the wells shown in Exhibit 3 can be classified as oil, based on the gas-to-oil ratio (GOR), with higher IP rates generated by the deeper wells (ie likely within the areas of higher fluid pressures). Some of the company’s more recent wells delivered even better results. Thus, Emery 17-2H, Barnes 8-4H and Brock 9-3H, all completed in 2022, generated impressive IP30 rates of 715 barrels of oil equivalent per day (boepd), 605boepd and 970boepd, respectively. To put this into perspective, the initial 30-day production rates used by the company for wells in this corridor assume an IP30 rate of 472boepd. Among possible factors we attribute this improved well performance to the company’s better understanding of the shale and, as a consequence, modifications made to the fracking techniques (for example, producing more fractures closer to the well bore and using more sand to improve permeability).

Due to the emerging nature of the oily Caney shale play in southern Oklahoma and its relatively smaller aerial extent compared to the more prominent Woodford and Springer formations in the region, publicly available geological data on this formation is relatively scarce. Kolibri’s exploration work on the Caney shale dates back to 2011 when the company conducted analysis and tested the formation by recompleting the existing Nickel Hill 26-1 Woodford well (initially drilled in 2007 and recompleted to Caney in 2011). These results led to the drilling of the company’s operated horizontal Barnes 6-2H well, which targeted two Lower Caney zones and the Upper Sycamore formation, which allowed testing of three different intervals and helped determine stratigraphically where to place laterals for the subsequent wells.

Based on the publicly available information, in 2013 the company recovered 100% of 423ft core from the Barnes 7-2H well (IP oil 523boepd, GOR 1,222), which spanned the interval from the base of the Springer formation across the entire Caney formation and the uppermost Sycamore formation (NB: Sycamore overlies Woodford Shale in Ardmore Basin). The core was analysed using Schlumberger-TerraTek tight rock services. While analysis of the quality of a shale play is complicated, there are a number of parameters that characterise an unconventional shale reservoir and could help assess its potential success. Some of these parameters include organic matter type, total organic carbon (TOC, organic matter quantity), vitrinite reflectance (VRo; thermal maturity, eg oil, condensate or gas window), effective porosity and permeability (see Exhibits 4 and 5).

Based on the conducted analysis it was concluded that the Caney shale in the Tishomingo field shares many characteristics of other successful shale plays. In particular the Lower/Upper Caney formation has thickness of 155ft; average TOC of 5% (2–12% range); thermal maturity, or vitrinite reflectance, of 0.99%, ie it is in the peak oil generation window; average effective porosity of 5% (4–5%) and average permeability of 137nD (105-199nD). It was noted that similar reservoir targets are also present in the Lower Caney ‘T Zone’ where the company has not defined any reserves yet. For comparison, the well-known and successful Bakken/Three Forks and Eagle Ford shales have the following characteristics: thickness of 10–250ft and 100–250ft; TOC of 5–20% and 3–7%; effective porosity of 5–10% and 6–9%.

As of December 2022, Kolibri had gross proved reserves of 33.3mmboe, with undeveloped reserves accounting for 82% of total. Proved oil reserves were reported at 24.9mmbbl, or 75% of the total, while shale gas and natural gas liquids (NGL) represented 14% and 11%, respectively. In addition, the company had 21.0mmboe in probable and 23.1mmboe in possible reserves, giving total gross reserves of 77.5mmboe. As shown in Exhibit 9, since the sale of its rights to the Woodford shale, the company has significantly increased its proved and probable (P&P) reserve base. From 2017, Kolibri has consistently maintained the level of gross P&P reserves at a c 52mmboe level, while its gross P&P and possible reserves have remained at a c 77mmboe level.

Assuming that a typical well produces c 500mboe over its operational life, the company’s undeveloped proved reserves would translate into some 55 wells, while probable and possible reserves would imply another c 88 wells. This is broadly in line with the company’s own calculations, which are based on more detailed analysis and well performance (Exhibit 7). At a rate of eight wells per annum (in line with the company’s drilling programme for 2023 and also our expectations for 2024), undeveloped gross proved reserves would support approximately seven years of drilling, while probable and possible reserves would add another c 11 years. Importantly, the 2022 reported reserves are solely based on Upper/Lower Caney and do not include the ‘T-zone’ portion of the shale that overlies the Upper Sycamore formation. This could represent additional upside to the reserve base and operational life of the shale.

As can be seen from Exhibit 8, Kolibri compares well against a group of selected peers based on the size of its P&P reserves, especially when viewed in the context of current production. The company has one of the highest shares of oil in its reserves, which together with low production costs results in superior operating netbacks (discussed below), and more importantly it has the highest share of undeveloped reserves in its proved reserve base. The latter points to a healthy and relatively low-risk production profile.

The company’s Caney shale produces three types of energy products – tight oil, shale gas and NGL. Given the oily nature of the shale, its production is heavily weighted towards oil, whose share in 9M23 output was 76% (on an oil equivalent basis), broadly in line with the gross proved reserves (75%). NGL contributed 14% to production, with the remainder accounted for by shale gas. Broadly speaking, production is a function of drilling activity and prevailing commodity prices. Thus, as a result of extremely low oil prices, Kolibri did not drill any wells in 2015–16 and 2019–21 (COVID-19 pandemic), essentially deferring production to later years.

More recently, however, the company has been ramping up drilling activity, capitalising on its substantial undeveloped reserves and the favourable commodity prices. In 2022, Kolibri drilled five wells and is guiding eight well completions in 2023 (five wells completed in January-November and three more wells are scheduled for completion in December). Increased drilling activity has translated into a visible step up in production, with an average output of 1,640boepd in 2022 and 2,780boepd in 9M23.

In addition to eight well completions in FY23, Kolibri has recently announced that it is planning to begin drilling the first well in its next three-well pad (consisting of two lower Caney wells and one T-zone well) in mid-December. Given that the oil price remains at relatively favourable levels for KEI, we expect the company to maintain its strong production momentum at least into 2024 and potentially further into 2025, capitalising on its significant undeveloped reserve base and attractive cost positioning.

A significant advantage of Kolibri’s business model is its attractive well economics. This leads to relatively high operating netbacks, as the company benefits from low operating costs and the high share of oil in its production. Exhibit 10 demonstrates the historical performance of Kolibri’s netbacks. We note that in Q1 and Q223, when the oil price was broadly in line with the current spot price of c US$70/bbl, the company generated an impressive operating netback of US$40/boe (NB: boe is not directly comparable to bbl as it includes gas and NGL production). Solid netbacks imply a relatively high oil break-even price, which in turn reduces earnings sensitivity to changes in commodity prices. Based on Q323 cost and revenue data, we estimate that the company’s break-even oil price was c US$40/bbl (including opex, royalties, capex and G&A), which compares well to the average WTI price during the quarter of US$82/bbl and the current spot price of US$72/bbl.

The cost competitiveness of the company’s business becomes apparent when its operating netbacks are compared to those of the peer group. As can be seen from Exhibit 11, where we show a selected group of broadly comparable mainly unconventional oil and gas plays, in 9M23 Kolibri had the highest operating netback (before commodity contracts), closely followed by Rubellite Energy (a heavy crude oil producer in Alberta, Canada). One of the main reasons for the company’s superior netbacks is a relatively high share of oil in its production mix and low operating expenses. The latter can be attributed to a number of reasons including the lower amount of naturally accruing water in the reservoir and the use of own gas required in the production process.

In 9M23, Kolibri’s opex of US$6.5/boe (including gas and NGL transportation costs, but excluding oil transportation, which is subtracted from the oil price) compared to a range of US$6.4/boe for Petrus and US$23.6/boe for ROK Resources, and the peer group median of US$10.9/boe. Low operating costs are somewhat offset by relatively high royalties, which we estimate are equivalent to c 22% of revenues. In all, the company’s 9M23 operating netback of US$42.5/boe compares to the peer median of US$18.9/boe. The high operating netback positions Kolibri as a defensive play among the selected peers, with lower operating leverage translating into less pronounced earnings volatility and therefore providing additional protection should the oil price continue to soften.

The company is run by an experienced management team. With over 36 years of conventional and unconventional E&P experience, KEI’s CEO and President Wolf Regener was instrumental in the formation of BNK Petroleum (now Kolibri) and its subsequent spinoff from Bankers. His career includes key senior executive positions with Tartan Energy, Alanmar Energy and R&R Resources, which involved heavy oil and enhanced recovery operations. Having an extensive operations and finance background, Wolf Regener has been at the forefront of Kolibri’s acquisition of unconventional projects on an international scale and development of the company’s Tishomingo Field interests.

The company’s CFO Gary Johnson (CPA) brought over 30 years of accounting and finance experience, of which 20 years in the oil and gas industry, to the company. His career includes roles with Occidental Petroleum Corporation, a Fortune 200 NYSE traded company, as director of technical accounting, Ascent Media Corporation as assistant controller and Western Atlas as the manager of financial reporting and analysis.

Greg Presley, KEI’s VP of engineering, and Allan Hemmy, senior geologist, have over two decades and over 13 years of industry related experience, respectively.

On 13 November Kolibri released its Q323 and 9M23 results. Production averaged 2,737boepd in Q3, an increase of 61% y-o-y, and 2,780boepd in 9M23, up 78% y-o-y. The increase in output was driven by new well completions, with three new wells commissioned in late 2022 and three more wells put into production in June 2023. Q3 production was partly affected by temporary well shut-ins to the tune of 200boepd. Net revenues after royalties were reported at US$12.7m, an increase of 29% y-o-y, with strong production offset by lower commodity prices. Operating expenses came in at US$7.3/boe versus US$7.8/boe in Q322, but were as low as US$6.5/boe in 9M23 (9M22: US$8.2/boe). The company achieved an impressive operating netback after commodity contracts of US$41.7/boe in Q323 (US$49.7/boe) and US$41.0/boe in 9M23 (US$48.5/boe). As a result, EBITDA came in at US$9.8m (Edison definition; company adjusted EBITDA of US$9.5m) in Q3 and US$29.2m (company adjusted US$28.6m) in 9M23, implying healthy gross revenue margins of 60% and 62%, respectively.

Net operating cash flow (OCF) was US$9.6m in Q323 and US$28.7m in 9M23. As the company continues to ramp up drilling and production activity, free cash flow remained negative at US$16.0m (OCF less capex and lease payments) in Q3 and US$35.1m in 9M23. The company reported net debt of US$24.8m at end September 2023, which translated into a comfortable net debt to annualised 9M23 EBITDA of 0.6x. At end Q3, it had available borrowing capacity of US$16m.

On 10 October, Kolibri provided updated production and financial guidance for FY23. It expects average production of 3,100–3,400boepd, revenue of US$57–62m and EBITDA of US$45–50m. This guidance is based on a WTI price of US$80/bbl, a Henry Hub gas price of US$3.0/mmbtu and an NGL price of US$32/bbl. Capex was guided at US$51–56m and year-end net debt at US$24–26m.

Our operational and financial forecasts for Kolibri are based on detailed well modelling using the public information provided by company. Our initial well production assumptions are based on the reported first 30-day well output (IP30). For the new wells we assume a share of oil/gas/NGL per barrel of oil equivalent output in line with the respective shares in the company’s reported proved reserves. Our decline rate assumptions are based on the exponential decline curve commonly used in the oil industry. While the full information on well flow rates, production decline rates and timing is not publicly available, our short-term production estimates could somewhat differ from the numbers reported by the company. With this in mind, we expect Kolibri to report average FY23 production of 3,034boepd, net revenues of US$54.4m and EBITDA of US$42.4m. One of the reasons our forecasts somewhat differ from the company’s guidance is commodity prices, as we assume an FY23 WTI benchmark price of US$77.5/bbl and a Henry Hub price of US$3.3/mmbtu.

Despite the recent downward pressure on oil prices, we currently expect Kolibri to maintain its strong drilling momentum into 2024, which should continue to drive earnings in FY24 and further in FY25. Having guided to eight well completions in FY23, we expect the company to drill another eight wells in 2024 followed by six wells in 2025. Based on our commodity price assumptions, we expect Kolibri to generate US$73m in EBITDA in FY24 and US$70m in FY25. The key risk to our forecasts is the oil price performance, which could affect drilling activity and well economics. However, we believe that the company’s consistently high operating netbacks and low operating leverage somewhat protect it from commodity price pressures.

More importantly, on the back of the increased drilling, we expect Kolibri to become free cash flow positive in FY24 and net cash positive in FY25. This suggests that the company could be in a strong position to start returning cash to shareholders or further accelerate development. While we do not factor any dividends or share buy backs into our model, we note that US$26m of free cash flow in FY25e equates to c 20% of the company’s current market capitalisation.

We do not attempt to forecast commodity prices and our oil and gas price assumptions are a blend between forward curve prices and consensus estimates, which are shown in the table above. Oil prices are driven by global supply and demand fundamentals and to a significant extent by OPEC+ decisions to reduce or increase production by its member states. However, while Saudi Arabia and other OPEC+ members have been implementing production cuts, oil prices have recently continued to weaken as a result of a strong supply side response coming from the US crude oil producers, in particular from the shale Permian basin in West Texas and New Mexico. With improving well level productivity and technological advances in fracking, shale players in the US have been actively ramping up production, with the US Energy Information Administration (EIA) estimating earlier this year that US oil crude production would rise 850mbd to a record level of 12.8mmbd in 2023. While Kolibri is a marginal producer in term of volumes, it is part of a general trend of increasing shale oil output in the US, benefiting from relatively favourable oil prices and its competitive cost position.

Our approach to valuing Kolibri is based on a DCF analysis. We have made detailed assumptions regarding the company’s future drilling activity, estimating the number of wells to be completed on an annual basis and certain well economics over the life of the company’s gross proved reserves adjusted for well spacing. Since our modelling is based on the last reported reserve data, it does not take into account potential additional resources from the so-called T-zone portion of the shale, which could further extend the life of the company’s operations. We value the company’s probable and possible reserves on a peer group EV/Reserves (gross) multiple, applying 50% risking to probable and 25% to possible reserves. Our NPV model for proved reserves is based a 10% discount rate. We assume a capital cost per well of US$6.2m based on the FY23 numbers, noting that the company has recently reported an average capex per well of about US$6.0m and a reduced drilling time of only 11 days per well. While Kolibri currently does not pay any tax, which is offset against still significant tax losses carried forward, for valuation purposes our model assumes tax payments start from FY26.

All in all, our combined valuation of the company stands at US$7.5 per share, or C$10.1/share. Given that Kolibri’s production is heavily weighted towards oil, our valuation is most sensitive to changes in our oil price assumptions. Below we show our valuation sensitivity analysis to changes in both the discount rate and the oil price. Based on the current share price and our operational assumptions, it appears that the market discounts a c US$55/bbl oil price at a 10% discount rate, or a higher discount rate of, say, 14%, and an oil price of c US$65/bbl.

Kolibri’s peer group comparison is complicated by the fact that the majority of oil and gas producers in SCOOP and STACK are either private or much larger players. Nevertheless, we have put together a peer group for illustrative purposes, which predominantly comprises the Canadian unconventional plays. Based on our estimates, Kolibri trades on an FY24e EV/EBITDA multiple of just 2.1x, versus the peer average of 2.4x. On an EV/reserves (gross P&P) multiple, the stock trades at 2.9x compared to the average of 3.0x. As discussed above we use the peer average EV/reserves multiple in our risked P&P reserves valuation for Kolibri. KEI has been the best performing stock within its peer group YTD as well as over one and three years (see Exhibit 18).

The key risks attached to Kolibri are commodity price performance, changes in environmental regulations and the global decarbonisation trends.

The company’s drilling activity and financial performance is highly dependent on oil and gas pricing. More recently, KEI did not complete any wells in 2019–21, as the WTI price averaged US$39/bbl in 2020 against the backdrop of a sharp economic slowdown due to COVID-19. While COVID-19 was an unprecedented exogenous shock to the global economy, in more normal economic conditions the company is relatively protected from soft oil prices due to its superior well level economics and netbacks. Yet KEI continues to rely on debt to grow output and needs to maintain high drilling volumes to gain production momentum and become free cash flow positive. As such, any pronounced decline in the oil price could affect the company’s ability and willingness to drill and therefore to grow production and cash flows.

In the longer term, the transition to a greener global economy poses a risk to oil and gas consumption and pricing, eventually leading to slowing demand for the company’s energy products. However, this transition is going to be a lengthy process, and the global economy will still require significant volumes of hydrocarbons before decarbonisation is achieved over the course of 20–30 years.

Finally, since the company is involved in hydraulic fracturing (or fracking), as part of the wider industry, it is subject to relatively strict environmental rules and limitations, mainly at the state level, that could potentially affect its ability to drill. While Oklahoma’s legal system is in general favourable to oil and gas development, the state has detailed legislation in place to control fracking activity, which is overseen by Oklahoma Corporation Commission’s (OCC’s) Oil and Gas Conservation Division (OGCD). Among other things, the OCC imposes regulations regarding drilling, operation, maintenance and abandonment of hydraulic fracturing wells in the state. In light of the increased seismic activity, in 2018 OCC issued a seismic protocol for oil and gas operators in STACK and SCOOP. It requires real time seismic readings, lowers the minimum level at which operators must take response to 2.0 magnitude and requires some operators to pause their activity for six hours when readings exceed 2.5 magnitude.