|Shares Out. (in M):||192||P/E||0||0|
|Market Cap (in $M):||666||P/FCF||0||0|
|Net Debt (in $M):||550||EBIT||0||0|
BELLATRIX EXPLORATION (BXE)
This write-up is denoted in Canadian $ unless noted otherwise
The recent tumble in oil and gas prices has presented a compelling opportunity to buy Bellatrix Exploration (BXE) at less than 50% of our conservative NAV estimate or 20% of our best case valuation. Assuming a modest recovery in oil and gas prices over the next couple of years, BXE offers an asymmetric payoff since the market is substantially undervaluing the company’s highly productive acreage in the Spirit River. Finding and development (F&D) costs on the company’s Spirit River wells are comparable to the lowest cost Marcellus and Utica shale plays. This makes the company a likely attractive acquisition target and could fetch BXE a nice premium based on recent M&A transactions. We do believe that concerns over management potentially diluting existing shareholders to raise additional capital are likely an overhang to the current share price. However, activist fund Orange Capital owns ~16.5% of BXE and has 2 directors, including co-founding partner, Daniel Lewis, of Orange Capital, appointed to the board. Orange Capital’s position should align management decisions with shareholder interests. Baupost Group also owns an 11% stake in the company.
(1) Moderate recovery in natural gas and crude oil prices over the next 2 years
(2) Management accelerates the development of low cost, high IRR wells in the Spirit River
(3) Completion of deep-cut gas processing facility
(4) Potential buyout
(1) Oil and gas prices remain depressed for more than 2-3 years
(2) Management issues additional shares under its $750M Shelf Prospectus
(3) Company is unable to extend the May 30, 2017 maturity of its $725M revolver
· North America oil and gas prices will continue to remain depressed driven by an oversupply in global markets
· Demand for Canadian natural gas will also continue to decline as it has over the past 5 years due to record production from U.S. shale plays such as the Marcellus
· Management will dilute existing shareholders in order to strengthen BXE’s balance sheet
Demand for natural gas from western Alberta has actually remained steady over the past 5 years because supplies from this region have normally been the lowest cost for the western U.S. BXE is also one of the lowest cost producers of natural gas in Canada with finding and development (F&D) costs on its liquids-rich Spirit River wells comparable to the lowest cost producers in the Marcellus and Utica shale plays. Based on management’s estimates on well economics, drilling BXE’s entire Spirit River resource potential of 398 wells alone over the next 10 years could deliver ~$6.50-$11.70 NAV per share even without the benefit of the deep cut facilities. This assumes a 15% tax rate and prices of ~$3.50/mcf for natural gas and ~$65/bbl for crude oil and does not even reflect the impact of increased NGL yields from BXE’s deep-cut gas plants. Also, note that BXE has only drilled 27 Spirit River wells over the past two years compared to 85 Cardium wells. Therefore, BXE’s financials do not fully reflect the low cost profile that solely focusing on drilling these Spirit River wells would deliver. We believe that Orange Capital is pushing management to at least put greater focus on developing these wells or evaluate a sale to a strategic buyer who could accelerate the development and maximize the NPV of these wells. Orange Capital also has two directors appointed to the board of directors, thus allowing better alignment of management and shareholder interests.
Company Description and Overview
BXE engages in the exploration and production of oil and gas resources in Western Central Alberta primarily through two core resource plays, the Cardium and Notikewin/Falher (Spirit River). Since converting to an exploration company in November of 2009 the Corporation has grown production by 232%, liquids production by 295%, reserves per share by 170% and cash flow per share by 226%. Much of this growth is driven by its productive resource plays as well as the company’s application of cutting edge horizontal drilling techniques to exploit each well’s full potential.
The company extracts raw natural gas from wellheads and sends the gas through processing facilities that separate the pure natural gas (methane) from the natural gas liquids (NGLs)—ethane, propane, butane, and condensate. BXE’s wells in the liquids rich Notikewin/Falher typically yield peak initial production (IP) rates of 4.0-25.0 MMcf/d versus 1.2 MMcf/d for the average well drilled in Western Canada. These liquids rich gas wells can generate an IRR>100% at natural gas prices of ~$3.50/mcf.
The Cardium resource play is the largest accumulation of light oil in the Western Canadian Sedimentary Basin (WCSB). BXE is a leading driller in the Cardium since its wells typically yield an IP90 rate of over 300 boe/d–the highest among its peers. These results are largely driven by the company’s adoption of cutting edge horizontal drilling techniques. As of 12-31-2014, there were 207 wells included in proved plus probable reserves and another 348 undrilled wells.
Production grew significantly from 8,500 boe/d in 2010 to over 38,000 boe/d in 2014 and is projected to increase to 43,000 boe/d in 2015 per management guidance. Over the same period, proved plus probable reserves grew from 42 mmboe in 2010 to over 250 mmboe in 2014 in order to sustain current and future production levels. Despite the substantial expansion of reserves, BXE still has significant upside in reserve potential from its unexplored acreage. As of 12-31-2014, BXE held a total of 322 proved plus probable well locations and an additional 1,288 undrilled well locations. Although not all of these wells may yield commercial value, the company has an impressive 100% success rate drilling to date.
Liquids Rich Spirit River Resource Play Provides Attractive Economics
BXE’s Spirit River resource play provides highly favorable well economics due to a combination of low F&D costs and liquids rich gas. Full cycle F&D well costs are budgeted at a range of $0.78/mcf-$1.11/mcf, which is almost comparable to some of the lowest cost producers in in the Marcellus and Utica shale plays. According to management, wells drilled in the Spirit River formation can deliver an IRR of 60%-130%, or $6.4-$11.4M in pre-tax 10-year NPV, depending on the estimated ultimate recovery (EUR) of the well. These rates of return assume full cycle capex of $5.7M per well and average realized natural gas prices of ~$3.50/mcf. Only ~25% of the wells drilled over the past 2 years were in the Spirit River. As of 2014 year end, BXE had a total resource potential of 398 wells in the Spirit River, but only 59 of these wells were included in the company’s total proved plus probable reserves of 322 wells. However, management stated in their Q1 2015 earnings call that the majority of drilling and completion capital in 2015 would be spent on developing Spirit River wells. They also mentioned that they are achieving costs of ~$4.2M per well, over 20% below the budgeted $5.7M, which implies an incredible F&D cost of ~$0.57/mcf-$0.81/mcf. To illustrate the potential value of these wells, let’s assume a 100% drilling success rate and the aforementioned well economics. This would imply that the 398 wells would deliver $1.3B-$2.4B ($6.4 to $11.4M * 398 wells * (1-15% tax rate)) in after-tax NPV over 10 years, or ~$6.50-$11.70 per share. Note that if the identical stream of gas is processed through the deep-cut gas facilities the profit margin would increase by 67% to $2.49/mcf from $1.49/mcf. If we apply the 67% increase to the NPV calculation above, the after-tax NPV increases to ~$10.80-$19.50 per share.
Source: Bellatrix Exploration Investor Presentation (May 2015)
Completion of Deep-Cut Gas Facilities Will Improve Operating Cost Structure
BXE is expected to increase its natural gas processing capacity by 220 MMcf/day, or over 125%, compared to 2015 following the completion of phases I and II of its deep-cut gas facilities. Management recently announced the completion of phase I on May 22, 2015, and phase II should be finished in 2017. The deep-cut facilities will capture nearly triple the amount of NGLs per volume of gas processed compared to existing third-party facilities. Assuming processing capacity is split 50/50 between third-party facilities and BXE’s deep-cut facilities, NGL (excluding condensate) yields will increase from 20 bbl per MMcf of gas to 39 bbl per MMcf of gas. As a result, management expects the increased liquids capture to increase the revenue from the same gas stream currently processed through third party plants by 14% and overall production expense to decline from ~$8.64/boe in 2014 to ~$7.20/boe by 2017. This cost reduction will save ~$40M annually based on overall production of ~80,000 boe/d in 2017.
Oil and Gas Pricing Should At Least Recover Modestly Over the Next 2-3 Years
Oil prices will need to rise over the next 2-3 years in order to support the capital investment required to meet demand of ~100M boe/d by 2020. According to Rystad Energy, onshore and offshore shelves are expected to supply 70M boe/d, while deepwater, shale, and oil sands developments will provide the remaining 30M boe/d. Deepwater and ultra-deepwater average break-even prices are ~USD$53-$57/bbl, while North America shale and oil sands have break-evens of USD$62/bbl and USD$74/bbl, respectively. Although the average break-even for the 20M boe/d from onshore Middle East developments is USD$29/bbl, the break-even for another ~30M boe/d from onshore developments in the rest of the world is USD$55/bbl. With the WTI and Brent crude oil benchmarks currently in the mid USD$50s, most deepwater, shale, oil sands, and even some onshore developments would be operating below break-even or just barely at break-even. Therefore, future growth in oil production is not sustainable at current market prices. Assuming most E&P companies would require a 20% margin and that shale producers set the price of oil, a normalized price for crude would be ~USD$75/bbl. This is calculated based on a 20% margin on USD$62/bbl—the average break-even for North American shale developments.
Natural gas production in Canada has declined ~22% since 2005 to 5.1 Tcf driven by low gas prices. If pricing remains pressured or continues to fall, production will likely resume its decline and be driven mainly by lower cost producers. Canada is a net exporter of natural gas since its production exceeds domestic consumption. Given infrastructure constraints, Canada only exports to the U.S., which is also importing less Canadian gas due to a surge in shale gas production. However, natural gas imports from Canada in the western U.S. have remained steady or slightly increased since natural gas prices at AECO-C Hub—the benchmark price of natural gas in Alberta—have usually been the lowest cost supplies for the western U.S. Therefore, exports of Canadian gas have mainly been displaced by U.S. shale plays, such as the Marcellus, in the Northeast and Midwest.
Natural gas consumption in the U.S. is expected to increase to 28.35 Tcf by 2025 based on the EIA 2014 Annual Energy Outlook and 32.5 Tcf according to IHS Global Insight. The increase in consumption is driven by the continued replacement of coal-fired power generation with natural gas and growth in industrial demand. New LNG liquefaction capacity will also demand more gas to export overseas.
LNG export terminals with ~0.7 Tcf of annual capacity are also expected to come online in Canada within the next few years. Additional export terminals are expected to bring total capacity to ~3.7 Tcf by 2020. These terminals will provide access to higher priced markets in Asia where spot cargoes for LNG ranged from USD$11-$18/mcf in 2014. However, the spread between Asian LNG market prices and North America prices needs to average at least USD$6.25/mcf to cover the costs to transport, liquefy, and ship the gas for export. With Henry Hub and AECO benchmark prices currently around USD$2.80/mcf and CAD$2.70/mcf, respectively, the start-up of additional LNG capacity should provide additional upside to natural gas prices.
Our NAV calculations are based on the sum of the NAV of proved plus probable reserves and the NAV of the company’s undrilled inventory of wells both over a 10-year period. We also present worst and best case scenarios for our valuation above. Secondly, we also use recent M&A transactions to benchmark BXE’s potential buyout offer.
NPV of Proved Plus Probable (2P) Reserves is ~$3.60/Share Under Base Case Scenario
Our conservative base case scenario assumes the average realized price over the next ten years for natural gas is a reasonable $3.69/mcf, which is ~23% below the $4.77 realized in 2014. Production will increase from ~180 mmcf/d in 2015 to 270 mmcf/d in 2016 as phase I of the deep cut plant will be fully online. Completion of phase II of the deep cut plant will then enable production to ramp up to 365 mmcf/d in 2017, and we assume that production will remain at that level through 2024. The company’s proved plus probable reserves are sufficient to support these production levels.
Given current weakness in NGL prices driven by low propane pricing, we assume that NGL prices will average $36.55/bbl, which is 14% below the $42.74/bbl realized in 2014, over the next ten years. Production of NGLs should increase from 6,133 bbl/d in 2014 to an average of 13,500 bbl/d driven by increased yield of NGLs via the deep-cut facilities. Management estimates that the combination of the deep-cut facilities and third-party processing facilities will extract about 39 bbls of NGLs per mmcf of natural gas, which implies ~13,500 bbl/d of NGL production based on 345 mmcf/d of processed gas.
For 2015-2024, we assume an average realized price for crude oil of $73/bbl, which is now nearly equal to the current trading price of the benchmark Edmonton Par. Production should increase from 6,336 bbl/d in 2014 to an average of 6,980 bbl/d over the next ten years as the company continues drilling through its reserves in the Cardium.
Based on these projections, BXE should generate ~$3.5B in operating cash flow and incur ~$1.9B in capital expenditures, including capex for the deep cut plants, during 2015-2024. Applying a 10% discount rate yields an NPV of ~$738M, or ~$3.60/share for the company’s proved plus probable reserves.
Unbooked Wells are Worth ~$7/share Under Base Case Scenario
There are 1,258 wells that are part of BXE’s undrilled resource potential. These wells are located in the Notikewin/Falher (Spirit River), Cardium, Duvernay, and Lower Mannville. However, the Spirit River wells are by far the most valuable assets in the company’s acreage. Assuming BXE starts drilling its remaining resource potential on top of its proved plus probable reserves from 2018-2027, we get an NPV of ~$7/share based on a 10% discount rate and a 15% tax rate—note that BXE currently utilizes its tax pools to offset its taxable income. In addition, we assume the company maintains its 100% drilling success rate in the Spirit River.
For the Notikewin/Falher (Spirit River) wells, management estimates the pre-tax 10-year NPV per well at $6.4M-$11.4M depending on the estimated ultimate recovery (EUR) per well. We used the midpoint, or $8.9M, of this range and assumed BXE would develop 32 wells per year, or its entire remaining resource potential within 10 years. Management mentioned on their Q1 2015 earnings call that the all-in cost per well is ~$4.2M, which implies an F&D cost of $0.57/mcf-$0.81/mcf. This range of F&D costs is in-line with the lowest cost producers in the Marcellus and Utica shale gas plays. The well economics assume AECO benchmark pricing of ~$3.50/mcf per year. For reference, the average realized price for natural gas was $4.77/mcf in 2014. Based on these assumptions, the Spirit River wells would have an NPV of ~$1.1B, or ~$5.60/share.
The cost to develop a well in the Cardium is ~$5M and generates an NPV of ~$3.2M according to management estimates. These estimates assume average forecast prices of WTI @ US$64.17/bbl, Edmonton Par benchmark @ $67.89/bbl, and AECO @ $3.38/mcf. The Edmonton Par Canadian light sweet crude benchmark has already recovered to ~$72/bbl as of June 2015. Therefore, wells in the Cardium are already able to achieve the aforementioned well economics. However, applying the $3.2M NPV per well to the 222 Cardium wells, or 2/3 of the undrilled Cardium resource potential, yields a NAV of $279M, or ~$1.35/share.
The other large resource play that BXE can exploit is the 415 wells it owns in the Duvernay. However, since the cost to develop a well in the Duvernay is ~$12M and likely generates a pre-tax NPV of ~$6M, we believe that management will not focus on developing these wells in the near term due to the higher up-front capital costs although they may choose to do so later.
From 2018-2027, the 546 unbooked wells included in our NPV calculation will require ~$2.5B of capital expenditures and deliver an after-tax NPV of ~$1.4B, or $6.95/share ($5.60 + $1.35), throughout this 10-year period even under our conservative assumptions stated above. There will also still be over 700 wells, primarily in the Duvernay, remaining after 2027 and currently have no value assigned to them.
We have also modeled a worst and best case scenario:
Worst Case: Assumes BXE recovers only 1/3 of its unproven resource potential in the Spirit River and Cardium, implying an NPV of $3.18/share. The NPV of the proved plus probable reserves remains the same at $3.64/share. Therefore, we get a NAV of $3.80/share, including net debt of $3/share.
Best Case: Assumes BXE’s average realized oil and gas pricing recovers to near 2014 levels. For reference, the average realized prices in 2014 for natural gas, crude oil, and NGLs were $4.77/mcf, $91.41/bbl, and $42.74/bbl, respectively. This scenario yields a NAV of ~$17.80/share, including net debt of $3/share.
Valuation Summary: Based on net debt of ~$3/share and a USD/CAD exchange rate of 1.24, BXE’s NAV is ~USD$3-$14.40 per share, representing upside of 9%-412%. BXE offers significant upside optionality if oil and gas prices recover to prior year levels but still a compelling asymmetric payoff even under our base and worst case scenarios.
Selling BXE to a Strategic Buyer Could Also Deliver Significant Upside
BXE owns a portfolio of high quality assets in the Spirit River and Cardium. As mentioned earlier, F&D costs for BXE’s Spirit River wells are ~$0.57/mcf-$0.81/mcf, which are comparable to the lowest cost producers in the Marcellus and Utica shale plays. Based on recent acquisitions in the E&P space, there are likely potential suitors who would be very interested in these assets. Repsol’s acquisition of Talisman Energy is probably the most comparable transaction to benchmark BXE against since both companies have nearly the same weighting towards natural gas. Assuming BXE is bought out at the same USD$9.40/boe of proved plus probable reserves as Talisman, BXE could potentially fetch ~USD$9.25/share, a 230% premium to the current share price.
Below we address the key risks to our investment thesis.
(1) Oil and gas prices remain depressed for more than 2 years
Although oil and gas prices impact our thesis, our base case scenario already assumes fairly conservative assumptions. Also, the Spirit River wells still generate a high rate of return at modest gas prices. Oil and gas prices should also not see further significant declines since most companies would rather cut capital investment than develop and produce incremental reserves at below break-even prices. The decline in production would then stabilize supply and demand in the market.
(2) Company is unable to extend the May 30, 2017 maturity of its $725M revolver
Given that the company’s creditor recently agreed to relax the financial covenants on its revolver in order to accommodate for the current market environment, we believe BXE should not have an issue with extending its revolver. However, if BXE is unable to extend its revolver, it can likely issue debt albeit at higher interest rates than it currently pays. Since the company’s revolver matures on May 30, 2017, there is still time to further evaluate potential credit risk a year from now if market conditions worsen or fail to improve.
(3) Management issues additional shares under its $750M Shelf Prospectus
Although the company has $577M worth of shares remaining that it can still sell under its shelf prospectus, management currently should not have the need or the incentives to dilute existing shareholders for several reasons:
- The company’s creditors recently amended the financial covenants for its existing credit facility by raising the Total Debt/EBITDA ceiling from 3.5x to 4.75x effective as of July 1, 2015 to June 30, 2016 and to 4.0x starting from July 1, 2016 to March 31, 2017. BXE maintained a 2.1x Debt/EBITDA ratio as of December 31, 2014. Therefore, BXE should not have to issue additional shares to pay down debt.
- Chairman W.C. (Mickey) Dunn owns ~835K shares. CEO Raymond Smith and CFO Edward Brown own ~450K and ~211K shares, respectively. Mr. Smith also held stock options in ~1.5M shares–1M of which had an exercise price above the current $3.35 share price. Given the number of shares and stock options that key senior executives own, they should not have an incentive to dilute existing shareholders at such currently low valuations.
- Orange Capital also currently owns over 31.5M shares, or a 16.5% stake, in Bellatrix Exploration. The activist fund also has two directors, Daniel Lewis and Steven Pully, appointed to the company’s board. Daniel Lewis is a co-founding partner of Orange Capital. Given Orange Capital’s large stake and its two board seats, it should hold enough influence to ensure shareholder interest is maintained.
(1) Moderate recovery in natural gas and crude oil prices over the next 2 years
(2) Management accelerates the development of low cost, high IRR wells in the Spirit River
(3) Completion of deep-cut gas processing facility
(4) Potential buyout
|Subject||A few questions|
|Entry||06/19/2015 12:50 PM|
Thank you for the write up. Could you please comment on their production costs, production taxes, and transportation and processing costs per mcf. Also, what kind of pricing are they getting (wellhead and at delivery point associated with their transportation and processing costs).
Related, are the f&d (and production, etc) costs readily calculated from their audited financials? Or are they management's projections?
Finally, is management non-promotional, have a history of good capital allocation?
Thanks a lot,
|Subject||Re: A few questions|
|Entry||06/20/2015 05:42 PM|
I'll try to address your questions, and I can further elaborate if needed.
Based on aduited financials, Bellatrix's production and processing costs averaged $8.64/boe in 2014 with crude oil, condensate, and NGLs at $8.47/boe and natural gas at $1.45/mcf. However, management is targeting production expense to decline in 2015 to ~$8.25/boe, which I think is pretty achievable based on:
(1) Q1 2015 production expense of $8.64/boe would have came in at $7,94/boe instead if you exclude the third-party facility equalizations
(2) The company renegotiated in Q1 2015 all major compressor rental agreements, which should provide ~$3.5M in annual savings
(3) Most importantly, the company just completed phase I of its Alder Flats deep-cut plant, which should provide most of the decrease in operating expenses and will enable production expense to decline to ~$7.60/boe in 2016 and $7.20/boe in 2017 once phase II of the deep-cut plant is completed
To touch more upon natural gas, production expense for the 2P reserves should decline from $1.45/mcf in 2014 to at least $1.20/mcf by 2017 as supply from BXE's Spirit River wells becomes more of a greater mix. Keep in mind that only 59 of the 398 spirit river well resource potential are included in the 2P reserves. These wells should run at $0.61/mcf per management. Even if this is potentially a little optimistic, it is still far below the current ~$1.40/mcf. The current operating expense structure reflects more of BXE's nat gas coming from its Cardium wells. These wells operate at roughly $8.50/boe based on the investor presentation. This is pretty close to BXE's current overall production expense.
The company's finding, development, and acquisition (FD&A) costs have averaged ~$10/boe over the past 3 years. If calculate F&D costs per the audited financials over the past few years that is around what you should get. Note that the full cycle F&D cost of a Cardium well is $10.81/boe per the investor presentation. As mentioned above, management focused more on developing its Cardium wells over the past couple of years since higher oil prices supported that rationale. With oil prices lower, management is now focusing on drilling more of its low cost, higher rate of return Spirit River wells this year. The F&D costs for the Spirit River wells are substantially lower and as the company focuses more of its drilling on these wells, the incremental F&D costs to bring on additional supply of natural gas and liquids from these wells should be at that ~$0.78-$1.09/mcf range per management estimates. However, just to note management commented in the Q1 2015 earnings call that the drilling and completion costs for each of these wells is coming in ~20% below what was presented in the recent investor presentation.
In regards to your question about pricing at the wellhead and delivery point, I will need to get back to you. I have reached out to IR on this. Let me know if there is another way you can think of in getting this info, and I'd be happy to dig.
I don't feel that management is too promotional. Their 2015 guidance for production of ~43,000 boe/d for example seems quite achievable given that was their run-rate in Q4 2014. Also, what they presented in terms of drilling and completion costs for their Spirit River wells is already coming in below what they had shown. Not to mention they completed phase I of their deep cut facility just in time as they had promised without delay.
In terms of capital allocation, management has already slashed their capex on drilling and completion for this year by more than half of their original 2015 budget. Of course they aren't the only ones since many other E&P players have done the same given the current pricing environment. Over the past few years though, they also pursued more JVs to fund their capex instead of leveraging their balance sheet with lots of debt as many other companies did. Now with oil prices much lower than they were over the past 2 years, they are turning their focus from drilling more of their oil weighted Cardium wells to their more profitable liquids rich Spirit River gas wells. And this is just in time to take advantage of their newly completed deep-cut gas processing facility.
|Subject||Re: Re: A few questions|
|Entry||06/22/2015 10:20 AM|
Broic, thank you.
Please post the pricing information when you receive it.
The other thing I forgot to ask was taxes and royalties. What kind or royalty rates and production taxes does the company currently pay. Also, what is the expectation for royalties/taxes going forward.
|Subject||Re: Re: Re: A few questions|
|Entry||06/24/2015 04:38 AM|
See below for oil and gas benchmark pricing and Bellatrix Exploration's average realized pricing for the past 2 years. You'll see that the Edmonton benchmark generally trades at a small discount to WTI and BXE's average realized price is slightly below the Edmonton benchmark. On the other hand, BXE's average realized price on natural gas is higher on average than the AECO benchmark since BXE's natural gas that is sold has a higher heat content than the industry average.
I also meant to mention last time that transportation costs average about $1.20/boe with natural gas transporation costs running in a range of $0.15/mcf - $0.20/mcf.
In regards to production royalties, BXE paid an average royalty rate of ~17% in 2014 and probably will pay ~18% in 2015. Bellatrix pays lower royalties of ~5% on more recent wells in their early years of production under the Alberta royalty incentive program. This is offset by increased royalty rates on wells coming off initial royalty incentive rates and wells drilled on Ferrier lands with higher combined Indian Oil and Gas and gross overriding royalty rates. I've assumed a royalty rate of ~17.5%--slighlty under the curent 18%--for the outer years in my valuation since the incresae in the drilling of new horizontal wells should blend to at least a rate below 18%.
|Subject||Re: Re: Re: Re: A few questions|
|Entry||06/24/2015 11:15 AM|
Thank you very much.
What's your take on Alberta's government talking about increasing royalties?
|Subject||Re: Re: Re: Re: Re: A few questions|
|Entry||06/27/2015 11:34 AM|
Alberta oil and gas operators have underperformed crude and nat gas by about 15%+ over the last 2 months since the stunning NDP win.
We feel that the royalties paid will increase albeit at a moderate amount and might increase with relations to higher commidity prices, but stay at current levels with low commodity prices. BXE's current exposure with regards to this royalty increase is roughly ~30% of its acreages and we recently modeled in a 15% increase in royalty payments which brings our base case scenario down by about $0.35.
We also wanted to only comment on this after the Government's announcement on Friday. Unfortunately, there weren't any details disclosed, but we now know that Dave Mowat will lead the panel for review and feel very comfortable with his expertise in understanding the energy business.
We will continue to update as things move along, but they are currently targeting the end of 2015 for a recommendation.
|Entry||07/22/2015 10:34 AM|
Only down 30%? That's one of the stronger performers in the sector recently!
|Subject||Outlook for Canadian production|
|Entry||08/24/2015 07:20 AM|
broic - your comment on the RRC thread led me to re-read your posting. How confident are you in the Canadian production outlook? My analysis leads me to be much more negative than you are. Canadian gas production was steeply declining for years (basically since 2006) due to poor relative economics vs. US shale plays, however that trend briefly reversed in the last two years b/c of the associated gas from liquids plays that were being drilled at $120 oil. Now that liquids plays are no longer economic, won't we see a structural decline in oil & gas production resume in Canada? It's high cost and marginal vs. the ocean of gas/liquids we have in the more competitive lower 48 shale plays that are much closer to load.
Has anyone else unearthed any good Canadian E&P shorts?
|Subject||Re: Outlook for Canadian production|
|Entry||08/24/2015 09:26 PM|
Thank you for reading over our write-up. We really admired your LNG write up in 2013 and look forward to your take on the overall E&P space and Canadian operators.
We agree with you that a big part of the increase in the last two years have been the associated gas alongside the liquids rich plays with oil at C$100+. There are a lot of struggling Canadian E&P companies and we follow almost all of them.
From what we see, overall productions in natural gas will decrease, but there are selective producers who are increasing current productions at these prices due to superior drilling economics.
If you happen to look at Peyto's slide on opex/boe, Peyto, Advantage, Tourmaline, Bellatrix, and Birchcliff have some of the lowest drilling economics you will ever find. Their drilling economics rival that of the Marcellus and Utica and in Peyto's and Advantage's case, they are better because of the concentrated asset base + own its own gas processing facility.
We think that an overall decrease in natural gas production in aggregate will be a positive to BXE, as it will reduce supply and provide a floor to current prices.
For additional insight into the Spirit River formation, we encourage you to read this write up: https://www.macquarieresearch.com/rp/d/r/publication.do?f=E&pub_id=7269086&file_name=080415Energy%20-%20Spirit%20Riverxe218634.pdf&
The reason why the superior drilling economics hasn't been reflected in BXE's opex/boe yet is due to the fact that the company still derives a good portion (40ish%) from the Cardium, which has opex/boe of C$8.5/boe as opposed to C$3.66/boe in the Spirit River.
Thank you for your question,
|Entry||09/18/2015 08:15 PM|
This only represents 11 areas and 3% of production, but we believe it is a postive indication that management is headed in the right direction of non-core asset sales. We think the pace and value of non-core dispositions will tick up over time, which will highlight the absurd value currently ignored by the market and serve as a positive catalyst for the stock.