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Good morning, and welcome to the Pipestone Energy Corp. Q2 2020 Financials and Operations Update Conference Call. [Operator Instructions]. As a reminder, this call may be recorded. I would now like to introduce your host for today's conference, Dan van Kessel, Vice President, Corporate Development. You may begin.
Thanks. Good morning, everyone, and thank you very much for joining the call. With me, I have Paul Wanklyn, President and Chief Executive Officer; Dustin Hoffman, Chief Operating Officer; and Craig Nieboer, Chief Financial Officer. On today's call, Paul will start by providing a summary of company highlights for the quarter. Dustin will follow with an overview of the operations update, and Craig will follow after that with an overview of our Q2 financial results. Following the discussion regarding our June 30, 2020, quarterly results, the team will provide a summary of the $70 million convertible preferred share financing, which we announced on August 5, 2020, as well as our accelerated development plan. I will now hand the call over to Craig Nieboer, Chief Financial Officer for Pipestone Energy, to provide the disclaimer and some comments relating to upcoming financial disclosure.
Thanks, Dan. Listeners should be advised that some of our remarks today will contain forward-looking statements within the meaning of applicable security laws. I refer you to our advisories regarding forward-looking statements, non-GAAP financial measures and capital management measures in today's press release and our MD&A. All dollar amounts referenced in our remarks today are in Canadian dollars unless otherwise specified. With that, I would like to pass it over to Paul Wanklyn, President and Chief Executive Officer, who'll provide a summary of the highlights for the quarter.
Thanks, Craig, and good morning, everyone. I'm very pleased to provide a quick summary of the highlights of the second quarter for Pipestone Energy. In response to the increased volatility in crude oil prices and condensate differentials that prevailed during the quarter, Pipestone reacted swiftly to optimize its production from its existing pads. As a result of this optimization and the underlying quality of our asset, we were able to generate positive cash flow prior to significant hedging gains despite record low condensate pricing. The company continued to demonstrate best-in-class execution during the quarter as we successfully wrapped up our previously announced H1 2020 completions program 20% under budget. With that, I'll pass it over to Dustin to provide an overview of our Q2 operations.
Thanks, Paul. As Paul mentioned, throughout Q2 2020, Pipestone Energy actively managed its production in response to increased volatility in crude oil prices and condensate differentials that prevailed during the quarter. Specifically, condensate production was optimized month-to-month by shutting in the 7-well 6-24 pad during May and gradually bringing it back on in response to improved pricing during June. The company benefited from strong plant run times at both the Keyera Wapiti Gas Plant and Tidewater Pipestone Gas Plant, averaging 96% for the quarter. This is compared to 70% during Q1 2020. The company has significant incremental production capability with 6 wells recently completed and tied in on the 6-30 pad. This pad is being tested during July and August and will be shut in until October when we'll it bring on full time. I'll now turn it over to Craig to walk us through an overview of the Q2 financials.
Thanks, Dustin. During the second quarter of 2020, the company generated revenues of $26.4 million and adjusted funds flow of $11.2 million, respectively. As Dustin detailed, our production was managed during the quarter in response to low commodity prices, and we still managed to average 16,772 BOEs a day during the quarter, comprised of 29% condensate and 43% total liquids. As a result of our robust hedging program in place, the company realized commodity hedging gains of $10.4 million during the quarter, ultimately protecting our cash flows and liquidity through the period of sharp declines in crude oil prices and condensate differentials. In terms of the capital program during Q2, the company spent just under $20 million, with the majority of that being spent on the H1 2020 completions program as detailed by Paul and Dustin and again, reminding listeners, completed 20% under budget. From a liquidity perspective, as of June 30, 2020, the company had $183 million drawn on its RBL credit facility, excluding letters of credit and a $13 million working capital deficit for a combined net debt of approximately $196 million. Paul is now going to take us through the convertible preferred share financing and its significance to the company.
Thanks, Craig. On August 5, 2020, the company announced a $70 million convertible preferred share financing to fund an accelerated development plan and put the company on track for an aggressive growth trajectory over the next 2 years. The accelerated development program that we're pursuing will bring forward value and materially increase our go-forward free cash flow generation capability. The significance of the commitments made by our largest existing investors speaks volumes in regards to the quality of our assets as well as their support for our business plan and our team. This financing will allow Pipestone to pursue an aggressive capital program for the next 2 years and capture value from the company's highly economic drilling inventory. The company has been able to achieve significant growth to date, growing from approximately 1,500 BOEs a day of production a year ago to 17,000 BOEs per day today with 27 new wells brought on stream in that period. Over the next 2 years, the company will aim to bring onstream approximately 30 new wells per year, ultimately growing to over 34,000 BOEs a day in 2022. We expect that through a continuous and optimized development plan at USD 40 WTI or better, the company can deliver its goal of generating top-decile returns, enhance its scale and deliver meaningful free cash flow above maintenance capital after 2022. The terms of the financing represent an attractive premium to the current common share trading price. And it's expected that the execution of our accelerated development plan will generate higher per share metrics on a fully diluted basis than the status quo. Craig is now going to provide a more detailed overview of the terms of the financing.
Thanks, Paul. As we previously released, the company has entered into subscription agreements with certain affiliates of Riverstone, GMT Capital and GMT Exploration with respect to the financing. The financing is for the issuance of $70 million worth of 70,000 convertible preferred shares or CP Shares. The CP shares have a term of 5 years from issuance and are convertible to common shares at a conversion price of $0.85 per share or approximately 70% premium to the 30-day VWAP from August 4, 2020. As mentioned by Paul, this is a very attractive premium for the company on a convertible instrument. Holders of the CP Shares are entitled to a 6.5% annual dividend that is payable in kind or in cash after 2 years from issuance at the sole discretion of the company. In consideration for backstopping the entire financing, the CP Shares were sold at a price of $970 per share for net proceeds of approximately $67 million after all anticipated transaction costs. It should be emphasized that if not previously converted to common shares by the holders at maturity, the CP Shares will convert to common shares, and as such, there will be no cash obligations for Pipestone under this instrument. The financing is subject to shareholder approval and is expected to close on or about September 15 after our scheduled upcoming AGM on September 14. In connection with the financing, Pipestone has reconfirmed and executed an amendment to its $225 million reserve-based lending facility with our corporate banking syndicate. With the significant equity injection into our business and our accelerated development plan, Pipestone's banking syndicate agreed to forgo the fall borrowing base review and defer that until our next scheduled redetermination in May 2021. Additionally, as press released previously, Pipestone closed on a $15 million unsecured letter of credit facility under the Export Development Canada's performance security guarantee or PSG program. The company has subsequently transferred its $14 million worth of letters of credit from its RBL credit facility to the PSG facility. The result is Pipestone has full access now to its $225 million RBL to fund its business plan. Pipestone has currently drawn approximately $190 million on this RBL, and post close of the financing, the draw will be around $120 million, leaving more than $100 million of available RBL on which to draw upon and execute our business plan. The financing will allow Pipestone -- sorry, that's -- sorry. I will now turn it over to Dustin, who will provide an overview of our accelerated development plan.
Thanks, Craig. Contingent on closing the financing, Pipestone Energy will be increasing its 2020 capital guidance from $60 million to $110 million. In September 2020, the company expects to utilize 2 drilling rigs to drill 6 wells on its 3-12 pad. This pad will be completed in November and available for production by year-end. On the 8-15 pad, 1 rig will be utilized to drill 4 additional wells starting in November 2020. These are expected to be completed and brought on stream during Q1 2021. In 2021, the company plans to undertake a continuous drilling program, utilizing up the 2 rigs along the North-South gathering system. The program will be designed to optimize the infrastructure capital spent to date. In 2021, Pipestone Energy aims to bring between 28 and 32 new wells on production, anticipates capital spending to be approximately $210 million, more than 90% of which will be on drilling, completion and equipment tie-in costs and expects to produce between 24,000 and 26,000 BOE per day. I'll now turn the call over to Dan to walk through our hedging program.
Thanks, Dustin. Pipestone is committed to continuing its robust hedging program with respect to expected condensate volumes through calendar 2021. Currently, for full year 2021, the company has about 40,000 GJs per day of AECO natural gas hedged at a weighted average price of $2.35 per GJ. And we have 2,500 barrels a day of Canadian-dollar WTI hedged at a weighted average price of approximately CAD 57 or just over USD 42. And with that, I'll hand it over to Paul to conclude the call.
Thanks, Dan. Pipestone is well positioned to become one of the larger condensate-rich Montney-focused producers as we embark on an aggressive growth strategy over the next 3 years. We truly believe that post financing, Pipestone is uniquely positioned to deliver significant production and cash flow growth on a per share basis as well as top-decile corporate returns, while maintaining a healthy balance sheet for the foreseeable future. And with that, I'll turn it over to the operator for question-and-answer. Thank you, ladies and gentlemen, for listening in.
[Operator Instructions] Our first question comes from Amir Arif with Cormark Securities.
Congratulations on the financing. I think it's great to accelerate at this time when service costs are low. So just a question on the service cost side. Given that you're starting up activity again here in September, can you give us a sense of, as you're going out to bid, what -- where you see service costs relative to your average well cost recently? I think you're factoring in $6 million in your budget going forward.
Yes. Thanks, Amir. It's Dustin. I'll take that one. Yes, you're right. We're budgeting $6 million of it -- I'll remind the audience, our 6-30 pad did come in at a pacesetting $5.3 million per well DCET cost. Our expectations here at start-up is service costs should be moderately better than where we left off in Q2 of this year. But again, I will remind you that a lot of the efficiencies that we've garnered over the last number of months have been really more driven to our scope and efficiencies in our operations. We haven't necessarily been relying on huge discounts from our service providers. But we would anticipate to see some wins relative to Q2 this year.
Okay. Sounds good. And then just a second question. On the -- just in terms of sensitivity on the '21 plan. So the 2020 outspend is covered through the financing. In terms of the 2021, at what oil price would you slow down from the plan that you've laid out in terms of the $210 million spend?
Yes. I'll take this one. It's Dan van Kessel. I think, at least partially, we're continuing to work on hedging the plan at the underlying USD 42 per barrel budget price. And we're -- our weighted average hedge price is in excess of that today, and we've got an opportunity to continue layering on at a price above the budget price. But I think if you saw oil back down to, call it, $35 per barrel and that looked like that was the outlook for a period of time, we would adjust our plans accordingly. But part of what we're embarking on here is to compensate for the dilution as they execute on the plan and have a robust risk management strategy that underpins the cash flow required to fund that strategy.
Maybe as an add-on to that, Amir, it's Paul. Current forward strip for gas is certainly ahead of our budget price of $2.25 as well, and we've been actively hedging into that strip. So you should expect us to be -- to get to sort of in and around 50% on both commodities sometime in the next few months on a go-forward basis.
Okay. Sounds good. And just a final question. On the pad drilling that you will do in 2021, are you planning on targeting all the same zones? Or you're high grading that plan to try to derisk the '21 plan on the production side?
Yes. We're prudently managing how we have laid out our pad as far as spacing and stacking goes, Amir. I mean, obviously, at a USD 40 WTI environment, we will high grade, if necessary. But I will remind you, our economics are very robust at the $6 million well cost. And if we can continue to deliver on the pacesetter well costs, we'll have no problems sticking to our current plan. One of the key things that we're always doing is we're always trying to learn from our existing pads. So we've done a number of projects where we've run ultrasonic imaging on our wellbores to try to determine cluster efficiency. We do have a plan for this later this summer to run some; dip in fiber optic logging tools, again, to just help ensure that we've got great conformance along our laterals, and we're maximizing our deliverability on our current design. But you shouldn't anticipate us to change our spacing and stacking materially from where we've been historically.
Our next question comes from Tyler Maguire with Peters & Co.
Just as a follow-up to one of the previous questions, how might the capital program change if, say, we're in a higher commodity price environment? Do you think you guys would start to add a little bit more spending on the kind of central or eastern portion of the acreage? Or are you just sticking to the current plan?And then can you also remind us when you guys would need further infrastructure requirements, whether it be through third-party facilities or your own infrastructure? At what point, I guess, on the production side?
Yes. Tyler, it's Paul. Thanks for the question. No, I think we're -- oil recovery to $50 wouldn't probably push us to pick up any more activity next year. We think the pace is really a strong pace. It basically is 1 rig for the first quarter, next -- in '21 and then switching to a 2-rig program. And that's where our current thinking is. It's not obviously Board approved but -- so that program, we think, is a great cadence and goes a long way to filling this first phase of our infrastructure, which will be filled up in 2022. Your question on infrastructure, we're looking at lots of opportunities. I think there are a number of midstreamers out there that have excess capacity that could be easily connected to our area. And we'll be examining all sorts of opportunities for those midstreamers to come basically to our front door to collect our product. So I don't -- we don't see a major infrastructure expenditure from our perspective in the next couple of years. So as Dustin said, for 2021 and certainly for 2022, 90% of our capital goes to DCET, so really pretty focused and efficient way to capitalize the project.
Yes. Just a couple of specifics would be -- we think no problem. Our existing infield gathering infrastructure could handle the midpoint of our 2022 forecast of 36,000 BOEs a day. With some minor additional debottlenecking expenditures, we think we could get that to 40,000. And then in terms of third-party requirements, we think that sometime in 2022, we'll need some additional processing capacity.
Okay, perfect. And then just thinking about the amount of wells that you're bringing on and -- into the 2021 program. I know through Q2, you guys were able to manage production, shut in some of the higher condensate wells and things like that. Maybe just curious on how you're thinking about that going forward. Obviously, because if you're bringing on a lot of wells, there could be some high-flush production and some decent declines.
Yes, I'll talk to maybe how we've laid out the pad development for next year, Tyler. It was -- we consciously looked at the gathering system capacity limitations and made sure that we distributed the pad accordingly along the spine, our North-South spine. Prime example, the 8-15 pad that we teed up here for drilling this fall and completing in Q1 next year, that pad site is adjacent to our 8-15 compressor station. And so there's -- it's a prime example of just managing away any potential base backout by bringing on flush production along that gathering system. So we don't anticipate really any issues at all as far as base backout or being able to deliver the production profile that we've laid out in our guidance with the current plan.
[Operator Instructions] Our next question comes from Josef Schachter with Schachter Energy.
Congratulations on the good quarter and the financing and the growth in front of you, which is definitely not what we're seeing from the patch in general. I have 2 questions. One, on the letter of credit with the EDC, how long was the process? How difficult was the process? And are you the first one through the queue getting this kind of financing? And do you see the process moving more smoothly for everyone else who's in the queue so that we could start seeing more repetitive announcements of EDC or BDC support coming to the industry, which has been a problem?
Josef, this is Craig, the CFO. I'll take that. First of all, we're very appreciative of EDC's support. But I think we were very fortunate to actually be in the process on having this letter of credit facility, which was an existing facility that they had in place before they started bringing programs to support the oil and gas industry in general that have been announced this year. So we were well down the path. We were well down the path on approval. We're well down the path on know your client. We're well down path and approved on the environmental side, and we actually got held up somewhat by the new programs that got announced and the process that were really put a lot of pressure on the EDC folks to look at other things. So we kind of got actually delayed in what we were doing with them on the letter of credit facility. So again, very happy we got the letter of credit facility done with EDC, very happy for the support. Provides additional liquidity for us under the RBL, which is the most important thing to our business. As far as your conjecture as what the go-forward for EDC and the industry is, I mean, that's a challenging question. I think we all have different opinions. We haven't seen a lot of action on that file so far. But from our perspective, we got what we needed from EDC, so we're very happy.
Okay, super. That clarifies that. Second question, Paul, the -- we've seen concentration in 2 deals already in the BC side of the border for the Montney. We haven't seen anything on the Alberta side, the more liquids-rich side. How do you perceive what's going on in terms of the acquisitions that are going on in the BC side? Is that more related to the LNG Canada and the feed there? Or do you see the consolidation of the Montney on both sides of the border starting to happen now that we have more firm natural gas prices and better liquids prices?
Yes. That's a very good question. Thanks, Josef. I think ultimately, LNG Canada may play a part in that, certainly in the bigger gas plays that you've seen. The Conoco, the announced Conoco acquisition probably doesn't fit into that one as much because that's a condensate -- more of a condensate play at Inga. I think you're going to start to see more in Alberta as well. The Delphi transaction was announced, and it's not closed yet, but that's the start probably in Alberta. I think you'll probably see a wave across Western Canada. Just -- yes, hard to speculate what's going to be more active. But I think the wave will hit across Alberta as well.
Okay. Is there any implication on land values from either of those 2 deals that you can kind of extrapolate to the Alberta side of the border? Or is that -- there's only 2 transactions, and it's hard to -- 1 being maybe a take under because of the debt problems. What's your thoughts there?
Well, that's an interesting one because if you start to normalize on production value, and that's very difficult, dry gas versus condensate-rich gas. But if you do the exercise of normalizing on proven production value and then back out land values, you get numbers ranging from, on the high end, $1,000 an acre or more depending on the production value you're using, to basically 0 or negative land values on the low end of some of the transactions we've seen. So I don't think there's a rule of thumb we can all apply yet. It's all related to the quality of the asset being acquired. And certainly, the Conoco transaction highlighted a very healthy takeover value and a healthy land value. So on the Alberta side, yes, there's probably more potential for higher land values, given the trend in Alberta generally is chasing much more condensate-rich reservoir than generally you see in BC.
And I'm not showing any further questions at this time. I would now like to turn the call back over to Paul Wanklyn for any further remarks.
Thanks very much for joining us on the call this morning. We're very excited, as you can tell, to move the program forward and execute on the business plan that we've laid out. So I appreciate your time this morning, everybody.
Thank you. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.