Pengrowth Energy Corp (NYSE:PGH)
Q2 2016 Earnings Conference Call
August 05, 2016 08:30 AM ET
Derek Evans - President and CEO
Nick Lupick - AltaCorp Capital
Shailender Randhawa - RBC Capital Markets
Jason Frew - Credit Suisse
Good morning, ladies and gentlemen, and thank you for joining us on the call this morning. I am Derek Evans, President and CEO of Pengrowth. With me on the call this morning is Chris Webster, our Chief Financial Officer; Stephen De Maio, our Senior Vice President of Thermal Operations; Randy Steele, our Senior Vice President of Conventional Operations.
Before we begin, I’ll remind you that all figures presented are in Canadian dollars and certain informations presented today may constitute forward looking statements. Such statements reflect the current expectations, estimates, projections and assumptions of the Company. The forward looking statements are not guarantees of future performance and are subject to certain risks, which could cause actual performance and financial results in the future to vary materially from those contemplated in the forward-looking statements. For additional information on these risks, please see Pengrowth’s Annual Information Form under the headings Risk Factors and Forward-Looking Statements.
As we entered 2016, we set out additional initiatives that we were intended to safeguard the financial health and well being of the Company and articulated the actions that we were prepared to take to achieve these objectives. Our second quarter results clearly demonstrate the success of our efforts on cost reduction, production optimization and debt reduction. One of the objectives that we were keenly focused on was managing and reducing cost structures across the organizations. The relentless focus by our teams on upfront and the effort put forth has resulted in us achieving substantial savings and operating cost, general administrative costs, as well as reducing our transportation costs.
Second quarter operating costs of $66.7 million were lower than $40.1 million or 38% compared to the same period last year. Year-to-date operating expenses are lower by $62.9 million or 31% compared to the same period in 2015. A part of this result is attributed to our asset rationalization program where we’ve been successful in selling high cost assets and refocusing the portfolio on our lower cost assets.
The success of our efforts coupled with the expectation of further cost savings in operating expenses in the second half of 2016 has allowed Pengrowth to lower its operating guidance for aggregate operating cost by approximately $65 million in 2016, resulting in a new per Boe guidance range of $13.50 to $14.25 per Boe. This represents a decline of approximately 12% from the previously guidance range.
Similarly, second quarter cash G&A costs of $19 million were lower than 3.1% or 14% compared to the same period last year, while year-to-date costs were lower by $9.2 million or approximately 20%. These reductions resulted from lower personnel cost due to significant staff reductions in the second half of 2015 and the realignment of our employee benefit plans to be more reflective of current market conditions.
Operationally, our team’s focus on asset optimization has delivered strong results. In the second quarter, our daily production averaged 56,735 Boes per day, which was essentially unchanged from the first quarter after accounting for the impact of divested properties and scheduled turnaround activity, demonstrating the ongoing focus on production optimization and the low decline nature of Pengrowth’s asset base.
Our Lindbergh oil project continues to have performed expectations, delivering strong operational results and top cortile operating performance. During the quarter, we continued the strong performance with production averaging 50,532 barrels per day an average steam oil ratio of 2.35. Thus far in 2016, production results from Lindbergh have tracked closely to expectations and the project remains on track to achieve average annual production of 15,700 barrels per day in 2016, well above the projects nameplate capacity of 12,500 barrels per day. Also in the quarter we announced receipt of the anticipated Environmental Protection & Enhancement Act approval for the expansion of Lindbergh to 30,000 barrels per day. This approval not only allows us to expand nameplate production capacity of Lindbergh to 30,000 barrels per day, but it also allows Pengrowth to continue to produce phase one above the current 12,500 barrel a day nameplate capacity. Furthermore, the approval provides the opportunity for additional incremental optimization capital to take production to approximately 18,000 barrels a day.
We continue to see strong evidence of improving capital efficiencies on both conventional and thermal sides of our business. Montney productivity continues to improve with associated declining capital cost. The thermal business continues to demonstrate strong capital reductions with Lindbergh phase two cost estimates down by an estimated 20% on a year-over-year basis.
Consistent with our commitment to improve our financial health, we have been working on a number of fronts to reinforce the strength of our balance sheet by focusing on debt reduction. I am happy to report that we have made substantial progress on this front. Since the beginning of the year, our outstanding debt has been reduced by approximately $225 million and year-over-year our debt has been lowered by approximately $371 million. The majority of this effort has been focused on retaining our credit facility and following the repayment of an additional $52 million during the quarter, we exit this quarter with nothing drawn on our $1 billion committed revolving covenant based credit facility. In addition, the Company exited the quarter with an approximate $54 million of cash on the balance sheet and expects to have $150 million to $200 million of cash on hand by the end of the year.
Turning to our ongoing asset disposition program, we’re continuing with the process and are taking a measured approach with the program to ensure that the Company achieves maximum value for any assets sold. We’ve seen an improvement in sentiments as commodity prices have strengthened and we’ll look for opportunities to capitalize on this improvement to achieve a fair value for any assets that we sell. Thus far in 2016, we have harvested disposition proceeds of approximately $47 million and continue to target disposition proceeds of approximately $300 million in 2016. I would point out that this is not a prior sales process, and due to the strength of our hedging profile and the support that it has provided to our cash flows, we can be patience and thoughtful with this process.
We also continued to hedge to protect our cash flows through the use of fixed price contracts on our crude oil and natural gas. These activities have proved to be valuable throughout the last 18 months. The benefit of our hedging program is evidenced by the strength and stability to our operating net backs and resulting funds flow over the past few quarters. In the second quarter, we’ve realized hedging gains of $77.1 million or $14.93 per Boe leading to second quarter funds flow of $89.1 million or $0.16 a share. On a year-to-date basis, we have realized hedging gains in excess of $200 million or $18.88 per Boe in support of funds flow and over $530 million of gains since the end of 2014.
We remain well hedged throughout 2016 as core prices well in excess of current prices and have strong hedge positions for both crude oil and natural gas in 2017. These positions will allow us to lock in a portion of our 2017 cash flows while still providing the Company with some exposure to price movements.
In closing, we remain focused and committed to reducing all our cost structure across the business, optimizing our production and ensuring that any capital that has put to work in the business is done at the highest capital reinvestment efficiency. We have made great progress on improving our balance sheet by reducing our outstanding debt year-to-date and expecting continue directing all excess cash flow from our hedging program, disposition proceeds and funds flow from operations towards further reductions in our outstanding debt positions. These achievements will improve the strength of the Company and position us to capture the benefits of a strengthening commodity price environment.
This concludes the formal part of the call. And we will now take questions from our analysts. We encourage all our shareholders with questions to follow up with our Investor Relations team. We’ll be happy to address any and all of your questions. Donan, please open up the queue for questions from our analysts, at this time.
Thank you. We will now take questions from the telephone line [Operator Instructions]. And the first question is from Nick Lupick from AltaCorp Capital. Please go ahead.
My first question is about Lindbergh. Last quarter you guys tempered expectations a little bit in that you had a bit of a lowered plateau production somewhere in the kind of just over 16,000 barrel per day range, and now we are talking about getting to 18,000 with a little bit of de-bottle necking or some kind of a brown field expansion. I was wondering if you could talk a little bit more about that, maybe how much money it might cost? What it entails. Is it as easy as adding a couple more wells or well pairs, and also, maybe the timing on that as well?
Thanks for the question Nick. The short answer is that there is more capacity clearly in phase one, we think that capacity is somewhere in the 18,000 barrels a day range. I think you’ll hear us come out in our third quarter press release talking about how we’re going to capture and optimize that opportunity. And to sum up the timing on it is reflective of when we actually hit peak production and where we think the declines are going to be. But I think it's fair to say that we would expect that in the current cost environment we should be able to add capacity in that $15,000 per Boe range.
Following up on that, if you were to go back call it six months ago, you would look at the type curve assumptions that you guys had at the wells and they were showing a decline kind of in the four year time frame. Clearly, with the pilot we are pretty much at four years now and those wells are producing over 700 barrels per day on average. Can you update us kind of on what your -- do you have revised expectations of when you expect the pilot wells to go into decline?
Well, pilot wells are a decline and have been for some time. As you remember they peaked out at about 1,000 barrels a day some time ago. The interesting part is in the parts that is little challenging for us is we originally model those pilot wells to have a decline somewhere in the neighborhood of 30%. Currently, we think that decline is closer to 20% to 22%. But it's still very early days in terms of how we’re looking at that. So, I guess the short answer is we expect to see at some point as improvement in that decline reflected potentially in our reserves. But I don’t think our reserve consultant will actually let that happen until they see not only the pilot wells having demonstrated that decline that also our commercial wells.
Fair enough. The one other question I had, do you guys have any turnarounds planned for the third quarter coming up here across any parts of the portfolio?
Yes, we have relatively large turnaround at Carson Creek plant. And in addition to those turnaround, we’ve got a fair amount of integrity work that we will be undertaking on a number of our property. So, when you look at our capital program and our operating costs, we’ve got relatively low operating costs in the second quarter. You should expect that the third quarter operating costs will be slightly higher, reflecting some of that integrity work as well as some of that turnaround work. And that our capital spend in the third quarter will be higher than it was in the second quarter for the same reasons.
Thank you. The next question is from Shailender Randhawa from RBC Capital Markets. Please go ahead.
My question is on the cost estimate for Lindbergh Phase II. You mentioned the 20% year-over-year reduction, Derek. Just wonder if you could give us what the gross numbers might look like for the approval that you have? And where are you seeing the cost reductions? Is it more on the labor side versus equipment? And could you characterize any ability to lock in prices if you were to find a way to move forward funding?
Shailender, thanks for the question, it's a good one. At the Annual Meeting, we pointed to the fact that we’ve seen -- there is actually a graph in the presentation and it points to the CEO’s attention deficit disorder in terms of going back to the thermal group and say tell me how much the costs have come down every two months. So we have a fair number of data points on that graph and they show a consistent decrease in capital costs, somewhere down in that $650 million range currently. I personally expect that those costs are going to continue to come down. And part of the thesis here is that when you look at the capital dollars that are being spent in the basin and let's just say that that $30 billion this year they’re evenly split at the current time between thermal and conventional.
And the reason for that is there is a large number of thermal projects that are in the final stages of clearing up. We expect that as those projects finish up and move up, the capital spend will probably be $2 billion to $3 billion in the thermal space, which will add increasing pressure to the costs in the thermal side. So, yes, we see 20% cost reductions on a year-over-year basis. We expect that those costs will continue to come down. And as a result we are not too keen on walking in costs at this juncture.
The other part of your question was with respect to where are we seeing those cost reductions, I think we can say that we’re seeing lot of cost reductions, more on the material side of the business at this point in time. There has been some labor cost savings that we anticipate they will be there, but you can imagine with $15 billion worth capital still be spent in that sector, we likely have not seen the ultimate cost reductions that we could see on the labor front.
Thank you. The next question is from Jason Frew from Credit Suisse. Please go ahead.
Derek, I'm just wondering if you could give us some color on what you are seeing from an industry point of view around your Montney asset at Bernadet and just like how would you characterize your entry costs today versus what you're seeing in terms of industry results.
Just to clarify, how would I characterize our entry costs?
Just the position you have taken there, your entry cost there, and just in light of what you have seen in terms of well performance since entering that asset?
Well, don’t get me started on how much I love the Montney and why I think it's the best gas play in North America. And truly I think is a much stronger and better asset than what the Marcellus did. The challenge was that Montney is not so much the reservoir rock or productivity, but really talks to that transportation disadvantage that we have inside North America. When we entered Brownsburg which was our first Montney purchase, and if we went back and we pulled the archives I think we would have assigned a 3 Bcf EUR to all of those wells.
As we look at our project in Brownsburg today, we’re seeing EURs in the 8 to 9 Bcf type range. And breakeven economics that drive down to well into the low $2 in Mcf. So I would characterize our experiences very, very positive one. But one that I don’t think is over, I think we’re going to continue to see substantial improvements in well length, perforating density, sand concentrations, fluid delivery systems. We’re going to continue to see how much costs have come down. And I can’t point out or I can’t emphasize enough how important it is that both our Brownsburg Bernadet positions are in what I consider to be one of the best natural gas place in North America.
And are you seeing anything in particular around Bernadet in terms of the industry and liquids content or any update there?
We continue to watch what one of our neighbors to the west is doing. And I think this is fairly consistent with our philosophy in terms of how we spend capital. We are not in a rush to get out there and develop massive amounts of volumes. We feel that there is a huge advantage to being not fast follower but a slow follower, watching other operators continue to invest in the technology and move us along that learning curve.
With respect to Bernadet, there are some data points further to the west, there is some data points now further to the north. I think you will see us license probably three wells in Bernadet later on this year. And start the evaluation work to actually hold that -- turn that lease into a license. And that would probably work that we would undertake in late 2017 or early 2018, and probably with capital costs somewhere in the neighborhood of $14.5 million.
And then maybe for Chris just on some of the tone and the text around the covenants. Can you just speak to what is triggering a little bit more of a cautionary view there? Is it just where we are sitting in terms of the cycle on the commodity or is there anything else we need to think about?
Jason Chris has just stepped out perhaps a second, so let me try and answer that question. You're quite right in taking up on more of a cautionary tone. I think there is two reasons for that versus almost I think it would be inappropriate if we didn’t point to situations or conditions where we could or could not pay debt covenant. And we are not alone in that. But I think we’re seeing much greater degree of cautionary language from all participants in the oil and gas business on that front.
The other peculiarity of this whole situation from my perspective is the fact that as commodity prices fall away as they are in the current situation our situation gets strong by virtue of the strong hedge position that we have. But the key message is in the, that we put out there is that in the second half using the GLJ price deck and I think it $0.75 FX, that you could have a challenge in the second half of the year.
And then my final question is on the cost performance which looks quite good. The change in the guidance $65 million, some of that I am guessing is related to lower variable power and gas. So when you think about extending forward maybe a year forward, how much of that $65 million should we think about translating to an ongoing cost reduction? And that’d be my final question. Thanks.
So I think if you break down the cost components, there is power, there is property dispositions, and ongoing work in terms of reducing chemical consumptions. But I think the biggest takeaway is that the overall mix of properties has changed to one that is lower cost and ultimately with the lower decline. So when you look at your operating cost on a dollar per Boe basis, one of the things is most people focus on what is the dollar components, be they power or chemicals.
But having a very low decline helps ensure that your per unit costs are not walking away from you. So, the load decline nature of the asset base I think helps assure us that we’re going to have to be able to continue this operating cost piece going forward. And the fact that we got rid of some higher operating costs pieces, the ongoing work on chemical and the labor costs, all have come down and we expect those to stay down as we drive forward.
Thank you. There are no further questions registered at this time. I’d like to turn the meeting back over to Mr. Evans.
Thank you, Donna. And thank you to, ladies and gentlemen, for joining us on our call. This ends the cal. And I hope everybody has great day and a great weekend during the summer. Thank you all.
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