Canacol Energy Ltd (CNECCL.SN) Earnings Call Transcript & Summary

Good morning, and welcome to the Canacol Energy Second Quarter 2020 Financial Results Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Carolina Orozco, Director of Investor Relations. Please go ahead.

Good morning, and welcome to Canacol's Second Quarter 2020 Financial Results Conference Call. This is Carolina Orozco, Director of Investor Relations. I am with Mr. Charle Gamba, President and Chief Executive Officer; and Mr. Jason Bednar, Chief Financial Officer. Before we begin, it's important to mention that the comments on this call by Canacol's senior management can include projections of the corporation's future performance. These projections neither constitute any commitment as to future results nor take into account risks or uncertainties that could materialize. As a result, Canacol assumes no responsibility in the event that future results are different from the projections shared on this conference call. Please note that all finance figures on this call are denominated in U.S. dollars. We will begin the presentation with our President and CEO, Mr. Charle Gamba, who will cover the operational highlights for the second quarter 2020. Mr. Jason Bednar, our CFO, will then discuss financial highlights. Mr. Gamba will close with a discussion of the corporation's outlook for the remainder of fiscal year 2020. A Q&A session will follow. Mr. Gamba is joining us on the line from Bogotá, and Mr. Jason is joining us on the line from Calgary. I will now turn the call over to Mr. Charle Gamba, President and CEO of Canacol Energy.

Thanks, Carolina. Good morning, afternoon or evening, everyone, and welcome to Canacol's Second Quarter 2020 Conference Call. Nominated contractual gas sales during Q2 2020 were 171 million standard cubic feet per day, a 35% increase from the same period in 2019. Cash revenues net of transportation during Q2 of 2020 were $62.1 million, an 18% increase from the same period last year. None of our take-or-pay gas sales contracts have been in dispute during the quarter. Nominated contractual gas sales for the second quarter of 2020 reached a low point of 156 million standard cubic feet per day in April and recovered to 185 million standard cubic feet per day in June. The demand began to recover after the countrywide lockdown related to COVID. In the second quarter, we continued to execute our capital plan with no significant cut to our 2020 capital budgets. We also continue to deliver on our return of capital to shareholders via the continuation of our quarterly dividend program with no cut. Unlike the majority of oil and gas companies operating here in Colombia, we did not suspend capital spending during the second quarter, but rather took advantage of the opportunity to secure a second drilling rig at a significant discount along with the deep discounts for the current drilling rig under contract. As I mentioned, we also continue to issue our quarterly dividend with no cut. Production operations during the second quarter ran smoothly with no major interruptions. Drilling operations suspended on March 26, 2020, due to the national lockdown resumed on May 27, 2020, after the lockdown was lifted. Biosecurity protocols in accordance with local and federal guidelines and laws have been implemented in all of our operations and offices, the priority being placed is always on the safety and health of our employees and contractors. Finally, in a major show of confidence in the stability of Canacol's business model, our syndicated lenders extended our existing $30 million term debt facility at a lower interest rate than before and extended us a further $121 million in new low interest term and revolving credit during the period where many oil and gas producers have their borrowing bases redetermined and cut. I will now turn the presentation over to Jason Bednar, our CFO, who will discuss our second quarter financials in more detail. When he's done, I will provide detail on the outlook for the remainder of 2020.

Thanks, Charle. Q2 2020 was another strong quarter for Canacol, both operationally and financially, as we continue to execute our plan and drive our growing natural gas business forward. Focusing on the second quarter of 2020, financial highlights include: revenues increasing 14% to $54 million compared to $48 million for the same period in 2019; adjusted funds from operations increasing 22% to $31 million from $26 million; EBITDA increasing 9% to $40 million from $37 million; and net income increasing 843% to $18 million from $2 million. As Charle already outlined, sales volumes declined from Q1 levels due to lower demand. However, thanks to the large pipeline capacity expansion project completed in late August 2019 and its related new take-or-pay sales contracts that came in in-force in the second half of last year, we still reported a 22% increase in funds flow from operations relative to the same period in the prior year. And with capital expenditures constrained slightly by COVID-related restrictions, we were able to generate $19.2 million in free cash flow before interest and dividend payments. That's only slightly lower than Q1 and substantially higher than any quarter before that. That free cash flow supports our unchanged quarterly dividend that was initiated in the fourth quarter of last year, which currently represents an annual yield of approximately 5.8% with the last dividend paid in July. And the free cash flow also supports continued improvement in our leverage ratios. Our net debt-to-EBITDAX ratio is reduced from 2.3x at June 30, 2019, to 1.8x at June 30, 2020. Our operating netback decreased 7% to $3.63 per Mcf in the 3 months ended March 31, 2020, compared to $3.88 per Mcf in the same period of 2019. Sorry, my apologies, that was for the Q2, June 30. The decrease is due to a lack of premium spot price -- premium spot market gas sales as a result of the lower demand driven by COVID-19 economic downturn. That decrease is partially offset by a reduction of operating expenses per Mcf to $0.25 per Mcf for the 3 months ended June 30, 2020, compared to $0.31 per Mcf for the same period in 2019. As expected, increased gas sales allowed us to substantially decrease our operating costs on a per unit basis. Given the COVID quarantines, we did defer some routine maintenance work in Q2 to the latter half of the year, which effectively reduced Q2 OpEx and increased second half OpEx to some extent. Also notable is the decrease in royalty expenses to $0.64 or 14.1% in Q2, down from $0.72 or 15.9% in Q1 of 2020. This results from the reduced sales in Q2 and our ability to shift production between blocks, allowing us to produce a higher percentage of that production from Esperanza block, which has a lower royalty rate. It is worth noting that we maintained strong operating margins of 80% during the quarter. Relative to the first quarter of this year, we were actually able to increase our operating netback and margin very slightly despite significantly lower sales volumes, which I think, again, speaks to the strength of our business and the value of our sales contracts in particular. We recorded net income of $17.7 million for Q2 2020 compared to $1.9 million for the same period in 2019. Unlike Q1 of 2020, where we saw a large devaluation of the Colombian peso and recorded a large noncash deferred tax expense, the peso strengthened in the second quarter of 2020, which allowed us to post an $11.6 million deferred tax recovery. Should the peso strengthen further throughout 2020, our net income would reflect further deferred tax recoveries. I'll also mention that the modest peso hedge we had in place expired on July 31, 2020, and the company now has no hedges in place. Our cash and cash equivalents increased from $41.2 million at December 31, 2019, and from $49.2 million at March 31, 2020, to $58.5 million as at June 30, 2020. The financial strength and stability of our operations is giving us increased financial flexibility. As such, we've been able to reprofile a portion of our existing debt as well as add a couple of other important pieces as announced last week. I won't go through the full details of everything we did, which is in the press release released last week as well as our financial statements and summarized on this slide, but I will highlight some noteworthy achievements and give some insight as to the rationale for them. So first of all, we were able to reprofile our existing $30 million term loan that we entered in December 2018, which allowed us to buy the Jobo 2 gas processing facility and that's operated and lowered our OpEx at the same time. The facility carried an interest rate of 6.875%. In June of 2020, as the first amortization payments were coming due, we renegotiated the rate down to approximately 4.5% and pushed out the first amortization payment to December of 2021. This 18-month extension adds approximately $16 million of additional liquidity to the corporation through to the end of 2021 based on principal payments alone. The second piece related to a new $46 million revolving credit facility, which is at approximately 5% interest rates if and when drawn. Although Canacol ended Q2 with approximately $59 million of cash and can fund its capital and dividend programs with existing cash flows, we thought it prudent given the favorable rates to add to our financial flexibility. Third and lastly, we negotiated a $75 million bridge term loan at approximately 4.5%, which resides inside the company that will build the Medellin pipeline. The first $25 million will be drawn shortly and will be used to fund expenditures, such as engineering and environmental permitting through to June 2021. The remaining $50 million could be used to order long lead time items, such as pipe, when the timing is appropriate. We anticipate that during the term of the bridge, Canacol will divest between 75% to 100% of the shares of this subsidiary to an equity partner, while maintaining up to a 25% working interest in the ownership of the pipeline project. Once the equity partners and bank syndicate agreements have been signed and any applicable conditions precedent been met, we anticipate the long-term funding will be advanced and the bridge will be repaid in its entirety. These 3 debt deals come in at a time when many North American oil and gas producers seem to be rolling over their debt without any significant improvement in terms. I think we can be proud of what we've achieved operationally, which underpins our ability to lower our cost of capital in this way and to secure substantially increased financial flexibility. I think it's fair to say we're seeing our cost of capital decline as market participants come to understand the value of our business. On the debt side, that is reflected in these new terms and the expanded debt capacity, while on the equity side, it is reflected in a very stable share price compared to many other oil and gas producers. During 2020, the company plans to use its excess cash to: number one, maintain our quarterly dividend payment, which has been set at CAD 0.052 a share, which is approximately a 6% dividend yield at current share prices, totaling approximately $13.5 million for the first half of 2020; secondly, to continue to repurchase common shares of the corporation under our normal course issuer bid when you feel it is right to do so. In closing, our Q2 financial results were very strong and relatively stable despite the challenges that the coronavirus pandemic presented. And now we are in an increasingly enviable position of financial strength with flexibility to ramp up investment levels when we think it makes sense to do so. At this point, I'll hand it back to Charle. Thanks, everyone.

Thanks, Jason. The stability provided by our fixed-term take-or-pay gas sales contracts have allowed us to weather the financial effects of this pandemic up to this point. We've maintained our growth strategy and have not put capital spend in a significant way. We also maintained robust cash flow and operating margins and have also maintained our return of capital to shareholders via the continued issuance of quarterly dividend, which we did not cut. With respect to the remainder of 2020, we reiterate gas sales guidance of between 170 million and 197 million standard cubic feet per day. Due to the 2-month delay in the drilling program related to the lockdown, we anticipate drilling 9 of the planned 12 exploration development wells in 2020 with the remainder being pushed into 2021. With respect to the capital budget, delays related to the lockdown and the above-mentioned reduction in the drill count, we anticipate spending approximately $108 million as opposed to the original $114 million. Currently, we're drilling the Porro 1 -- Porro Norte-1 exploration well, located approximately 25 kilometers to the north of our Pandereta field, located on our 100% operated VIM-5 E&P contract. Porro Norte-1 is targeting a 4-way anticlinal structural closure defined on 2D seismic. Potential gas-bearing reservoirs include the Tubara, Porquero and Cicucco sandstones and limestones. We're currently completing the Pandereta-8 well, and we'll then be mobilizing the other rig to the Pandereta-4 development well, which will test the potential Western extension of the Pandereta field. We expect results from both wells in September. Finally, I want to thank the entire Canacol team as well as our contractors, lending partners and clients for their support and hard work during these very uncertain times. We're now ready to answer any questions that you might have.

[Operator Instructions] The first question will come from Gavin Wylie with Scotiabank.

Two quick questions for me. So just looking for an update on what you're seeing in the spot market for Colombian gas pricing. As the economy has been slowly reopening, you've noted that gas demand, I think, got as low as maybe down 20% quarter over -- year-over-year back in April. I believe that, that was recovered to maybe only down about 5% year-over-year in June, July. And again, just wondering, if you can kind of give us a sense of what you're seeing in the spot market as we are still dealing with those record-low hydropower reservoir levels? Second question is just on production. And given the volatility that we've seen through the last couple of months, just wondering if you can give us what, either July has averaged or kind of what you're seeing quarter-to-date relative to the 165 million cubic feet a day that you averaged in June. That would be great.

Thanks, Gavin. With respect to spot pricing and demand, we're entering in August, which will continue through to December, a typically strong cycle of gas demand. Historically, these are the stronger months for gas demand related to hydroelectric reservoir conditions. So we're seeing, as I think you've indicated, good recovery of demand, and spot pricing, of course, is tagging along with demand. So as demand continues to increase, we see spot pricing coming back up away from those lows that we experienced in April and May, certainly. With respect to production, July and August, we're certainly well within the range of our published guidance, which would be between the 170 to 197 million standard cubic feet per day. So we're in pretty good shape.

Is there any specifics that you'd be willing to give on the pricing that you're seeing, just either what July average for spot market sales or on the like $1 per Mcf basis?

No. No, we're not going to give any specific spot pricing. Just to say that as demand has recovered -- is recovering spot prices increasing off Q2.

The next question will come from Josef Schachter with Schachter Energy Research.

Congratulations on a very nice quarter in these difficult times. Going back to the spot sales, the clients that are taking more gas, is it a few key clients that are taking more gas? Or is it across the board that you're seeing pickup in demand? I'm just wondering, is it related to individual customers? Or is it kind of just an industry issue, whereas the recovery of activity and business activity, then it's picking up right across the board?

Yes. Thanks, Josef. Thank you for that question. Good to hear you. Spot sales are following sort of the traditional pattern. As you know, the majority of our gas sales goes to thermoelectric power generation companies located on the Caribbean coast. And that's where the majority of our spot sales typically go. So those would be to either existing clients that we have existing take-or-pay contracts do that require additional gas, which they buy on a spot basis, or to other clients that we do not have take-or-pay contracts with other thermoelectric power plants that require gas. So I would say that the majority of spot sales, as always, go towards thermoelectric power plants. We're also selling spots into the regular industrial and manufacturing markets as well as demand has picked up there as well. But by and far, the large majority of spot sales traditionally goes to existing and other thermoelectric power clients.

Okay. Could you then go into what's going on in terms of the coronavirus and the reopening process, schools reopening, industry reopening? Are there any guidelines in terms of time line for when that pace will pick up?

So countrywide, the lockdown was lifted in May, which allowed us to resume our drilling operations, for example, in the departments where we have those activities. There are still currently local quarantines within some of the major cities. The major cities, for example, of Bogotá, Medellin and Cali. So certain sectors of the city are currently under lockdown. For example, in Bogotá, approximately 1/3 of the city is under quarantine, about 1.7 million people affected by that quarantine. And they've sort of been rotating the lockdown on a sector basis through the city. All of those lockdowns, certainly in Bogotá, will end on August 26. But countrywide, the lockdown was lifted in May. Hence, the majority of manufacturing and industrial mining, thermal power generation has resumed in the majority of the country. With respect to schools, for example, the schools are still virtual. There's no announcement of a plan to open schools anytime soon for the return of schools. And finally, with respect to air travel and transportation, the government -- the federal government, along with the local government, have started to reopen local airports for local travel -- local air travel, and it's anticipated that international air travel will resume on September 1. So that is essentially the schedule. The coronavirus itself reaching daily records of cases. So still very much on the uptick here in Colombia with respect to the lockdown generally being lifted across the country.

And last for me is you still have the Colombian oil numbers in 245 barrels, down from 342 in the prior year. When do you see that being sold or off the books and no longer part of the business operations?

Yes. That oil production comes from our last remaining oilfield, which would be the Rancho Hermoso field. Strangely enough, our very first oilfield in Colombia proves to be our very last field. We were in a sales process for that asset. We had concluded a negotiation with the party late last year. But that sales process fell apart basically. And as a result, we continue to operate that field, which at this current time, is still economic, believe it not. We're still receiving positive netbacks. And then we're making positive netbacks even at the lowest point of oil production. It is a very mature oilfield. We will continue with our efforts to try and sell that asset. And in the meantime, we will continue to operate that field at minimum operating conditions.

[Operator Instructions] The next question will be from [ Harry Malcolmson ], Investor.

The corporation's press release in November said that with respect to the Medellin pipe project, the corporation anticipates executing a take-or-pay sales contract with a major utility during the current month of November. Then in December, you indicated that the execution of a definitive agreement to construct a new gas pipeline will be undertaken and what are your targets for the 2020 year. At this point, it's apparent that those expectations were not realized. And I note that you have undertaken a workaround arrangement for -- which is constructive in the circumstances. I'm unclear, however, with respect to this pipeline, why the investor group that participated in the first pipeline consortium was reluctant presumably to participate in a -- further on. And basically, what are the factors that resulted in those reservations? In particular, was that a concern about LNG projects that might impact the economics of the second pipeline?

Thanks, [ Harry ], for those questions. Yes, with respect to the pipeline project at Medellin, we do have a long-term take-or-pay gas sales contract negotiated with the primary off-taker there. There are several events in Medellin at year-end which impacted the execution of that contract, primarily a change in the Mayor of Medellin who has some authority with respect to contract execution. So there's a change in there, basically. And then the client essentially with -- along with every other major clients here in Colombia was faced with the challenge of COVID, which they are still essentially faced with today. So the process has been very slow. But I will say that, number one, there is a take-or-pay sales contract negotiated to both parties' satisfaction; and number two, we continue in discussions with that client working towards the execution of that contract in the near term. All the investors in the project, the consortium that we have formed, and the investors we have attracted to this project along with our banking support are fully aware of the status of these negotiations and comfortable to the point of moving forward and in the financing that Jason just outlined. With respect to the other pipeline operator in Colombia that you referenced, we do have a number of parties who are interested in participating in the EPC contract, which will be responsible for the construction of that pipeline including several national pipeline operators. So I hope that answers your questions, [ Harry ].

Our next question will be from Nicolás Erazo with CrediCorp Capital.

Just one question about the deferred delivery you guys posted on the press release, past in July. We saw in the report of July that the additional nominations for deferred delivery were around 12 to 14 Mcf per day. But on the second quarter report yesterday, there is a figure of undelivered natural gas and LNG nominations of about 19 million cubic feet per day. So just to get to know what we are missing and because on the press release of July, we expected a -- between 12 million and 14 million and now the report says about 19 million. So just to get -- understand that figure, please.

Sure. I can certainly answer that. It's a great question because it is a bit confusing. So I'm going to start at the 19 million. As you know, we -- people -- historically, they can defer a portion as long as they pay for it, and they typically have 12 months to come and collect that gas, right? With COVID times, as we described in the previous quarterly conference call, we allowed people to defer additional volume. So that gross amount of deferral was indeed the 19 million that is in the MD&A and discussed here today. If we go back to my first part of the question, as people take their nominations in that 12 month cycle, they can then again defer some further nominations during that period. So the gross nomination deferrals for Q2 was 19 million, but 6 million actually collected their gas, leaving the net deferrals at the 13 million. I hope that's more clear.

Perfect, Jason. And just a follow-up. Given that the take-or-pay contracts has been sort of changing and given the flexibility you guys have made, which is great progress, what main changes besides the ability to defer volumes have been made on these type of contracts, meaning the take-or-pay contracts in terms of prices, in terms of tax effects against the U.S. dollar to be fixed or something? We know that that's something that has been changing a little bit in the couple of months.

Okay. Yes. Great follow-up question. So none of the prices have been changed. These are contracts. They're essentially set in stone. As we've said, there's no -- there's been no instances of force majeure, as we explained on the last call. Force majeure simply doesn't apply. And the contract prices are what they are. We have allowed some people to defer them. Also on this particular topic, we do -- if you look at our financial statements, there's about $15 million in deferred revenue. $5 million of that has actually been prepaid and not even nominated at this stage. For one reason or another, some of our off-takers simply prepay us for a full year of gas, which means the remaining $10 million has been the -- what I described. Also involved in this equation is the notion that we told certain contractors when we allowed -- off-takers rather, when we allowed them to defer volumes, that they had to take all of their contractual downtime for the year. A typical offtake contract has about 6% downtime embedded in it to allow the off-takers to do things like plant turnaround. Not everyone's going to take all 6%. But if they chose deferral, they would have to take all their downtime during the period that they deferred. So in one specific instance, one off-taker took all of their deferred -- their downtime days during the month of Q2 -- sorry, the period of Q2 rather.

[Operator Instructions] The next question will be from Ricardo Sandoval with Bancolombia.

Congratulations for the results. I have just one question at the moment. And it's about EPM. I just want to know how -- I mean, how -- what happened with EPM Board of Directors? I guess what happened in Medellin during this week with the Board of Directors of EPM? And how this would affect the negotiations of contracts for Medellin pipeline? I understood that EPM was one potential client for you. So I would like if you comment something about it.

Ricardo, thanks for the question. Yes, EPM is certainly one of the potential clients in Medellin with respect to sales contracts for the new pipeline. We're all aware of the issues -- internal issues currently affecting EPM. However, they are the largest public utility in Colombia, very sound financial structure and obviously require a long and steady supply of gas for the coming decades. So I would say that once they are through their internal restructuring, I expect business will return to normal, and they will continue to be a significant potential client for us in Medellin.

At this time, I'm showing no further questions from the phone. So I'd like to now turn the Q&A session over to Carolina Orozco who will handle any submitted questions.

Thank you, operator. We have one question from [ John Clark ]. What are the service dates for power plant and Medellin pipeline?

Okay. So I think I've already discussed the Medellin pipeline and where we're at with that project at the moment. With respect to the power plant, the power project, which we are participating with Celsia here in Colombia, the El Tesorito power project is a 200-megawatt electric power plant that will be constructed approximately 7 kilometers to the South and West of our Jobo treatment facility. That project is ongoing. The EPC contract was awarded in June. All environmental permits have been received by the consortium, and the project is on schedule for a December 1, 2021, start date. Our interest in the project, of course, is primarily related to the gas sales contract that we have with the consortium. So that's the update on the El Tesorito power project.

The next question is from Daniel Guardiola from BTG Pactual. In second quarter 2020, we saw spot volumes affected by the nationwide lockdown, but somehow offset by greater demand from power thermal generators due to weak hydrology. But in the last couple of months, hydrology has been rapidly recovering, which should reduce demand from gas power plants in the spot market. In that sense, I would like to know the potential implications in terms of pricing of these lower demand from generators.

Well, we did see unusually strong thermoelectric power consumption in the second quarter in what is normally a fairly wet period of time when thermal demand is quite low. However, if you look -- on a historical basis at sort of peak gas demand in the coast, the lowest demand months are, in fact, second quarter months, April, May and June, and then gas demand starts to pick up noticeably through the second half of the year, beginning of August through December. So we're actually entering a fairly -- historically, a fairly strong part of the demand cycle on an annual basis. But we see overall demand including thermal demand, historically, being at its highest point, historically through -- August through December. So I would say that we were very uncharacteristic this year with the unusually high thermal demand during April, May and June, which is normally a very low period of demand historically. As I mentioned a little earlier from one of the speakers' questions, the spot pricing is intimately related to demand. So if demand follows its historical path of strengthening through second half of the year, we should see spot prices react accordingly. If demand is weak, due to COVID or any other macroeconomic factors, we would expect to see spot prices be equally as weak. So I think at this point in time, we're pretty much forecasting our range of guidance, 170 to 197. Based on historic demand, coupled with the effects of coronavirus, spot pricing certainly is expected to be in sync with demand. So if demand is strong, spot pricing will be good. If demand is weak, spot pricing will be weak.

The next question is from [ James Branch ]. Is there any execution risk to getting investors in the new pipeline?

Perhaps I can answer that, Charle. So I've probably said on previous calls, pre-COVID -- so the pipeline is split into 2 components: one being debt, one being equity. We've had multiple ongoing discussions for the better part of a year with respect to that split. At this point in time, I expect the pipeline will be funded by approximately 30% equity and 70% debt. If I look at the debt side, we've been working with 2 large banks, which I expect to be the leads on that. Even pre-COVID times, I had term sheets on my desk with respect to conditions precedent and interest rates, et cetera. In the ongoing discussions, I don't expect that to change. So I feel the debt side will come together, and we've had abundant interest. On the equity side, it's expected to be private equity that will put up the equity component, with Canacol, of course, owning up to 25% of the equity. There has been abundant interest and continues to be abundant interest in that. Obviously, different private equity firms have different IRR hurdles. And obviously, we are looking to work with those that have the lowest IRR hurdles as the lower their expected IRR, the lower the pipeline tariff would be to Canacol and hence, the higher the netback we would get on our delivered gas to EPM and the other off-takers. So I've seen no decrease in the amount of interest and have actually seen arguably an increase in the interest in this particular project.

Next question is from Daniel Duarte from Corficolombiana. What is the total estimated cost of the Medellin pipeline project? What is the average gas sales price for just the take-or-pay contracts?

So total costs for the pipeline, I'd say approximately 300-kilometer long, 20-inch pipeline, extending from our gas-producing facility at Jobo, which is located in the department of Cordoba and will connect into Medellin city gate in the department of Antioquia. The first phase construction is planned to not include much in the way of compression. So the first [Technical Difficulty]

Pardon me, this is the operator. It appears his line has disconnected at this time. We'll get him connected as soon as we can. Thank you so much.

Carolina, if you maybe want to focus on some of the questions that are more financial and direct it my way, I can carry on.

Sure. So we received some questions from Luiz Carvalho from UBS. The first one is, I'd like to understand better your netback outlook for the next quarters.

Okay. So with respect to netbacks moving forward, let's just go through the components of the netback, if we can. Obviously, the largest component with respect to netback is going to be the sales price, right? So if interruptible demand continues to -- and I will cover off a couple questions that I see on my screen here. What is our average contracted price for the remainder of the year, that would be $4.72 net of transportation. So obviously, the interruptible sales price can move that average up or down. And at times, it's certainly moved it up. And obviously, during Q2, it moved it down. So depending on demand recovery, there's still a bit of a question mark with respect to what that top line revenue number would be net of transportation. The next component, of course, would be royalties. And in Q1, we saw a royalty rate of 16%. Obviously, we did approximately $202 million of sales. In Q2, during reduced sales, we were able to shift some of that production or produce more on a percentage basis rather from the Esperanza block, which has lower royalties, which I touched on earlier during my presentation. So in Q2, the royalty went down to 14%, once again, whereas Q2 -- Q1 was 16%. So once again, the royalties probably would end up in that 15-ish percent range, which would be $0.68 to $0.70 essentially. And the final factor, of course, would be operating costs. So we can see in Q1, while we were producing large volumes, our operating costs were $0.22. In Q2, when we produced less volumes, the operating costs were $0.25. The operating costs are largely fixed, being the cost to operate the Jobo gas plant. So the less volume you put through there, the higher the OpEx on a per unit basis, right? So those are the components. I will say that we have averaged historically going back to Q1 of 2018, as was on one of the slides earlier, anywhere between a 78% to an 81% operating margin. I don't expect that to change significantly through the latter half of the year. So it's really -- those things are all really dependent upon the interruptible sales markets and the price assumption that you may want to use for that.

Charle is now back in the line. So I'm going to read again the question he was answering. What is the total estimated cost of the Medellin pipeline project?

Yes. The total estimated cost of that project, 300-kilometer long pipeline project, is around $400 million for the Phase 1 cost, which will not include much compression.

The next question is from Luiz Carvalho from UBS. Can you please share some update about the new pipeline?

Yes. I think we've covered that topic here.

And the last question from Luiz Carvalho from UBS is in terms of demand. You mentioned about the lockdown scenario. Being on the ground, what is your expectation about full natural gas demand recovery with the new rules released by the government?

I expect demand will be highly dependent upon the course the virus takes going forward in Colombia. Specifically, if there is an inability to lower the incidence rates or the contagion rate, there might conceivably be a requirement for another lockdown, for example, to contain the virus. We hear a lot about first and second waves. And Colombia is very much at the midst of the first wave, with cases increase on a daily basis, reaching new record highs on a daily basis. So the outlook with respect to the trajectory of the virus remains quite uncertain and I think quite important with respect to the demand in general and economic recovery. If the virus continues on this path, and if there is indeed a second wave, I expect that we will see a demand hit. If this wave is controlled and a second wave, so to speak, does not materialize or is also controlled, I expect demand to recover. Those would be my thinking. So highly dependent upon what the federal local governments do with respect to lockdowns in response to the course of the coronavirus.

And finally, we have time for one last question from Mario Epelbaum from First New York. Coal-fueled electricity is being decommissioned in many countries. Do you expect any move in Colombia to decommission plants?

Thank you for that question, Mario. Yes, there are a few remaining coal-fired thermoelectric power plants, primarily on the coast. Colombia, of course, is a signatory to the Paris climate accord. And Colombia has strict goals with respect to CO2 emissions and targets for 2020. So the federal plan with respect to the plan for energy that the government unveiled in January of this year includes the gradual cutting out of coal-fired thermoelectric power plants and a substitution of that with natural gas. Eventually, of course, by 2050, the government plans to have a significant percentage of the energy matrix being supplied by renewable forms, which would include wind and solar. So gas and natural gas will play an important part in the transition away from coal and oil-fired power generation towards eventually an energy matrix dominated by renewables and, gas will, as I mentioned, sort of fill the in-between period from 2020 to 2050 in that transition that the government has mandated.

With this, we conclude our conference call today. Thank you all for participating in our second quarter conference call. And please join us again in November for our third quarter 2020 conference call. Have a great day.