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Pengrowth Energy Corporation (NYSE:PGH)

Q1 2014 Results Earnings Conference Call

May 13, 2014 08:30 AM ET

Executives

Derek Evans - President and CEO

Marlon McDougall - Chief Operating Officer

Chris Webster - Chief Financial Officer

Analysts

Mark Hughes - RBC Capital Markets

Kyle Preston - National Bank

Aaron Bilkoski - TD Securities

Operator

Good morning, ladies and gentlemen. Welcome to Pengrowth Energy Corporation’s 2014 First Quarter Results Conference Call and Webcast.

I would now like to turn the meeting over to Mr. Derek Evans, President and Chief Executive Officer. Please go ahead, Mr. Evans.

Derek Evans

Thank you, Valerie. Good morning, ladies and gentlemen. I’m Derek Evans, President and CEO of Pengrowth. Joining me today on the call are Marlon McDougall, our Chief Operating Officer; Chris Webster, our Chief Financial Officer; Bob Rosine, our Executive Vice President of Business Development; and Fred Kerr, our VP of Investor Relations.

Before we begin, I remind you that certain information presented today, may constitute forward-looking statements. Such statements reflect current expectations, estimates, projections and assumptions of the company. These 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, see Pengrowth’s Annual Information Form under the headings Risk Factors and Forward-looking Statements.

I’ll review Pengrowth's first quarter 2014 results. But first, I want to remind shareholders about Pengrowth’s strategy and our execution on that strategy. We continue to make strives on our journey of transforming Pengrowth into a sustainable low-decline dividend paying, free cash flowing energy producer.

2014 is our final year of this transition with construction of the first commercial 12,500 barrel a day facility at our Lindbergh project expected to be completed late in the summer with first steam in Q4. First oil production from Lindbergh is expected to come on in early Q1 of 2015 shifting Pengrowth's production significantly toward oil and resulting in funds flow per share that is expected to grow from approximately a $1 a share in 2014 to a $1.31 a share in 2015.

We realized that Pengrowth shareholders value receiving a dividend and remain committed to maintaining the dividend at current levels of $0.04 per share per month.

Pengrowth had a strong quarter, with production and funds flow from operations exceeding budget and guidance. We are delighted with the results of our non-thermal winter drilling program, the continued progress we have made on building the Lindbergh commercial facilities and operating the Lindbergh pilot, where performance continues to exceed expectations, we look forward to the successful completion of the Lindbergh commercial project and the expected significant cash flow growth starting in 2015.

I won’t rehash our quarterly report, which is very thorough, but I do want to make a couple of observation about our most recent financial results. Pengrowth achieved strong first quarter production with average production of 75,102 boes per day, primarily driven by strong Cardium drilling results from the Lochend and Garrington areas. We are on track to achieve full year guidance of 71,000 to 73,000 boes a day.

Although production in the quarter was 3% lower than the fourth quarter of 2013, average production of 77,371 barrels per day, the production declines were primarily in our natural gas production. Pengrowth has been following a strategy of investing in oil projects that provide high netbacks and fast payouts while investing very little in the natural gas side of the business. As a result, natural gas production declined 7% from the fourth quarter while liquids production remained unchanged.

Pengrowth generated strong funds flow from operations of $140 million in the first quarter of 2014, which represents a $34 million or 32% increase from the fourth quarter 2013 funds flow of $106 million. Higher natural gas prices coupled with the narrowing of light and heavy oil differentials during the quarter significantly increased revenues and funds flow. Funds flow per share increased 35% to $0.27 a share compared to funds flow per share of $0.20 a share in the fourth quarter of 2013.

First quarter 2014 operating expense of $104 million or $15.39 a boe decreased $5 million or 5% compared to the fourth quarter 2013 operating expense of $109 million or $15.34 a boe. Lower maintenance costs and the absence of operating costs on disposed properties closed in the fourth quarter were primary reasons behind the lower expenses in the quarter.

We expect Pengrowth operating expenses to be in the $17 per boe range for the second quarter, mainly due to planned seasonal plant turnaround that will reduce production volumes in the quarter. These higher unit operating costs were expected and are part of our full year guidance which we’re on track to meet.

Pengrowth’s non-thermal business continues to focus on oil and liquids development, primarily in the Cardium formation in the Lochend and Garrington areas where Pengrowth drilled 28 or 15.2 net wells in the quarter. Initial results indicate that the wells from the Cardium program continue to perform above our type curve expectations. Pengrowth is the most active Cardium driller in the Western Canadian Sedimentary Basin. Our Cardium drilling opportunities in the Lochend and Garrington areas are characterized by extensive 3 year to 4 year drilling inventories; rates of return of 35% to 46%; payouts of 1.9 years to 2.3 years; and recycle ratios of 2.7 to 3.8 times.

Drilling cost in the Cardium continued to decline with pad drilling and reduced drilling times, reducing cost by upto $200,000 per well. Completion cost per frac stage have declined allowing us to execute 18 to 19 stage fracs per well for the same cost as we used to spend for 15 to 16 stage fracs per well.

At Lindbergh, during the first quarter of 2014, civil and mechanical field construction continued for the first 12,500 barrel a day commercial phase and is progressing as planned. All major equipment has been set into place. And mechanical, electrical and instrument crews are completing final tie-ins. To date, Pengrowth has drilled 15 well pairs. Drilling of the second of the three well-pads is now complete and the drilling of the third well pad has commenced. Operations at the pilot continued to show strong results during the first quarter with combined fuel production from the two well carriers averaging approximately 1,780 well per day of bitumen. The average Instantaneous Steam Oil Ratio for the pilot in the quarter was 2.1. Since steaming commenced in February 2012, cumulative production from the two well carriers has reached approximately 1.2 million barrels of bitumen by March 31, 2014.

With over 75% of the first commercial phase capital spent or committed Pengrowth estimates total capital cost for the first commercial phase will increase from the initial $590 million estimate to the current estimate of $630 million. The $40 million increase is attributed to $20 million from higher base cost including currency exchange cost, $10 million for project scope changes made to enhance performance, $5 million for increased fuel and weather-related cost and $5 million for additional pre-investment in Phase II.

Pengrowth still expect the first commercial phase of Lindbergh to be on time with first steam in the fourth quarter of 2014 and first oil in early 2015. As a result of this increase in capital, Pengrowth is increasing its overall capital budget in 2014 by $40 million beyond the previously estimated range of $700 million to $730 million to a new range of $740 million to $770 million.

Pengrowth has engaged GLJ Petroleum Consultants to provide the independent Lindbergh reserve and contingent resource update prior to Pengrowth’s annual meeting on June 24, 2014. Pengrowth’s internal estimate suggest that this update will allow us to reclassify a significant portion of contingent resources to total proved and total proven plus probable reserves in the range of 70 million to 90 million barrels at Lindbergh.

This positive reclassification is primarily the result of additional delineation drilling which took place earlier this year and a larger development area associated with the environment or impact assessment applications submitted in December 2013 to expand the thermal project to 30,000 barrels a day.

Pengrowth remained on sound financial [putting] with approximately $315 million of cash on hand and an undrawn $1 billion committed credit facility as at March 31, 2014. The cash on hand will continue to be used in conjunction with internally generated cash flow to provide the capital for the completion of the first 12,500 barrels a day commercial phase of Lindbergh. Pengrowth expects to maintain a balanced cash flow profile through 2014 where by cash outflows including increased capital spending will equal cash inflows plus cash on hand.

Pengrowth continues to use hedging to mitigate commodity price risk, foreign exchange risk and power cost and to provide a measure of stability and predictability to cash flows; each of our hedging programs can be found in our first quarter MD&A.

Pengrowth transitioned to becoming a sustainable, low decline dividend paying free cash flowing energy producer remains on track. In 2014 the primary objective will continue to be to maintain Pengrowth’s dividend at current level of $0.04 per share per month, while continuing to execute on the commercial development of the Lindbergh thermal project ensuring Lindbergh is on time and on target for [steaming] in the fourth quarter of 2014 with first oil production in early 2015.

Pengrowth will continue to invest prudently in its non-thermal business, targeting the best oil and liquids opportunities that allow for the maximization of funds flow while continuing to be prudent in managing its balance sheet and maintaining financial flexibility.

This is an exciting time for Pengrowth. We look forward to updating you on the story at our Annual Meeting which is scheduled for June 24, 2014 and coincides with our Lindbergh reserve update.

We’d now be happy to answer any questions you have. Operator do we have any questions in the queue.

Question-and-Answer Session

Operator

Thank you Evans. We will now take questions from the telephone lines. (Operator Instructions). Thank you for your patience. Our first question is from Mark Hughes with RBC Capital Markets.

Mark Hughes - RBC Capital Markets

Thank you. Good morning gentlemen. Just a few questions surrounding the CapEx increase at Lindbergh, real surprise to see that at this stage. If you could maybe clarify what type of contingency portion or fund was in the original $590 million and if there is any contingency remaining in the updated budget?

Marlon McDougall

Mark, it's Marlon McDougall. So, in the original budget there was a 10% contingency built in that's fairly standard, I guess I would put forward that remembering this ASC which raised two years ago, currency has moved 10% since then and I would say 7% performance on a $600 million project is pretty good performance. I certainly think that there has been minor cost creek in a couple of areas, but we've also added some conscious pieces to the capital structure. So it's not just overspending, we then continue to invest prudently to make sure we are setup for future phases of Lindbergh as well.

Mark Hughes - RBC Capital Markets

Sure. So there was a 10% contingency in the original $590 million budget, that would be $59 million plus the $40 million increased that we just thought would be an actual budgetary pressure that’s probably closer to $100 million, is that a good (inaudible)?

Marlon McDougall

Sorry, get close to how much?

Chris Webster

No, I think, I mean back if you look at it that way Mark, I think really the issue really is how much pre-builds we've done and not only on the Phase II, but also in the original capital estimate, there is probably another $25 million worth of work that is attributed to Phase I or Phase II in that Phase I $590 million. I mean you can look at the map in that way, but it's in our maths little too simple.

Mark Hughes - RBC Capital Markets

Okay. Is there a contingency in the updated budget or is this sort of are we running kind of at the edge share?

Derek Evans

We're running about a 5% contingency in the updated budget, I mean we are 75% there. So there is very little, the final engineering work on well-pads and surface pipelines is now complete and that's where some of the cost creek was. We have everything ordered. So we know what the foreign exchange exposure is on everything. So really it's just the final mechanical tie-ins that are less to do. We have got the majority. Two-thirds of the well drilling is done. We have had good performance coming out of the second well-pad. So we don't believe that we’re exposed here at all. We’re in the final stretch of construction. And I guess I would just reiterate that I don’t believe that this is that much of a negative as far as the performance of construction, given timeline and complexity of work that’s going on.

Mark Hughes - RBC Capital Markets

Okay. So with -- as [list] prices of foreign exchange component, just the corporate strategy is very much one of risk communications, so I was surprised to see that sort of exposure on the FX side. Is there still exposure there or are we no longer sensitive to changes to the exchange?

Marlon McDougall

No, there is no exposure on that anymore. So those were pieces of equipment that were ordered and came out of the U.S. and are quoted in U.S. dollars, right. So, from the time we quote them to the time we actually pay the bill, the currency has moved 10%. So, we have significant foreign exchange hedging on the other parts of our business. But we did not do anything to hedge the cost from U.S. dollar purchase perspective.

Mark Hughes - RBC Capital Markets

So, was that a cautious decision not to hedge those purchases or how did that come about?

Marlon McDougall

Yes, it was.

Mark Hughes - RBC Capital Markets

Okay. How much of the cost pressure was schedule related to keep the project on schedule that often is (inaudible) something with other projects?

Marlon McDougall

Zero. These were all recognized, and out of the $40 million, let’s remember, there is only $20 million that is to do with engineering and FX and true what I would call additional costs. I mean we consciously made some scope changes to add in performance or add in pumps for performance at an earlier stage than we would have normally done. Cold weather and fuel costs, those were things that were just a fact of diesel cost at the time and we invested and continue to make sure that we invest prudently to make sure we are set up to maximize production. So none of this has to do with trying to get the project on time; it is on time there, just a result of some of the actual things that we incurred along the way.

Derek Evans

Mark, it’s Derek. I just want to reiterate what Marlon just said, there is -- and this incremental is not or this incremental capital is not being put to work to ensure on getting this project on time, nor are we cutting any corners in terms of development of this project. We are ensuring that everything that we anticipated is quite a substantial amount of incremental capital or to facilitate the seamless tie-in of our Phase 2 production is taken into account.

And so those are 2 absolutely critical points that I don’t -- I want to make sure that you and our shareholders recognize it. There is no cost cutting that is going on here in any way, shape or form and there is no capital being, none of this incremental capital is being used to ensure on time performance.

Mark Hughes - RBC Capital Markets

Okay. And just one final one, when I was on [site tour] at Lindbergh about 6 weeks ago, it was very much strongly reiterated that one way of keeping projects on schedule and on cost is to not make scope changes and just wondering what kind of -- what’s the rationale behind making scope changes at this stage of construction?

Marlon McDougall

So, this one is fairly simply, so typically when you have a SAGD project, your ESPs and your downhole pumps that you would put in are 6 to 9 months down the road. We certainly recognize a much faster ramp up in the Lindbergh area. And we want to be ready to have the pumps on decks so that we can put them in the wells as they start to heat up. So we just think that was accelerated that would have been capital where they got pushed out in significantly out into 2015. And although the pumps may go in the whole, it will be pretty close after year end. So we just want to recognize the cost of that in the short phase as opposed to having it as being additional capital down the road.

Mark Hughes - RBC Capital Markets

Okay, so there are no scope changes in facility event?

Marlon McDougall

No.

Mark Hughes - RBC Capital Markets

Okay, good. Thank you very much.

Operator

Thank you. Our next question is from Kyle Preston with National Bank. Please go ahead.

Kyle Preston - National Bank

Yes, thanks. Good morning, guys. Just a couple of questions here, first one following on the Lindbergh cost increase here. Just wondering how we should think about future phases here, I mean the total project cost I think is $2.145 billion if I remember correctly, and should we assume similar cost creep on that [estimate] as well?

Derek Evans

Kyle, it’s Derek. We have not generated [AFE] quality estimate for Phase 2 yet. I can tell you that we probably pre-invested somewhere in the neighborhood of $30 million, now in Phase 1 cost here to -- for Phase 2, it’s too early to tell you whether we think the costs are going to go up on Phase 2 or Phase 3 at this time, so we just haven’t done the work. And guess I want to reiterate that we are dealing with cost that we estimated back in November of 2012.

So clearly, it would be inappropriate for me to suggest that we have a much greater clarity on what [needs to do] with cost at this conjuncture.

Marlon McDougall

I think I would also add to that. Remember that we are not really going to be building this in a traditional fashion because of the productivity of the wells. We will be building out chop pieces of the next phase to focus on handling of bitumen. We believe that it won't be built in purely a modular fashion to have bolt-on the next full phase, it's going to be what I would say smeared across a couple of years because you're going to add fluid handling, you are going to add heat takeaway capacity and ultimately you will add more steam capacity, but those things will happen staggered from one another.

So it's going to be very difficult as you look forward to truly say what is phase two, because phase two will take two to three years to add and it will come in different chunks. We're going to be focused on minimizing the capital that we have to spend to maximize the bitumen production that we can get just given the productivity of the wells and the performance that we believe is going to be there.

So if we will be, as we come out next year, you are going to see a budget to allow us to enhance production and then be able to talk to what does it look like from an additional steam added perspective versus tankage versus pure bitumen handling and treating.

Kyle Preston - National Bank

And can you see approximately how much that is exposed to the move in the FX rates, stuff that you’re buying from the U.S. or elsewhere?

Derek Evans

The steam generators are the big ticket item; I don't have the cost rate off the top of my head, but they are the items that we have to source out of the U.S. So that is the piece of the construction, but I don't have the number right now.

Kyle Preston - National Bank

Okay. The other question I have is just on your production profile, obviously Q1 you had strong production there ahead of the top-end of your guidance. I mean how should we think about that production profile through the balance of the year? I know you mentioned there was turnaround come I think Q2 and Q3?

Derek Evans

Yes. So you're going to see, we were going to have some volume impact due to this turnaround in Q2 and not only on the production side, but I think Fred mentioned, you will also see it on the operating cost side. But we remain on target for our full year guidance on a production and on a cost perspective.

Kyle Preston - National Bank

Okay. Thanks a lot.

Derek Evans

Thank you.

Operator

Thank you. (Operator Instructions) Our next question is from Aaron Bilkoski with TD Securities. Please go ahead.

Aaron Bilkoski - TD Securities

Good morning, gentlemen. I was curious if you could provide some more color on the remediation provision, what happened and if you could (inaudible)?

Derek Evans

Certainly Aaron in January we had a pipeline still on the remote location in Northern Alberta regulators and local officials are aware of the events and the ongoing clean up. Our remediation efforts are ongoing and have been effective somewhat due to the (inaudible) and the remote location. We have cost to-date in the first quarter of about $4.5 million and we've made a provision for the whole amount that we think it's going to cost to clean up that’s built in our first quarter?

Aaron Bilkoski - TD Securities

Thank you.

Operator

Thank you. There are no further questions registered at this time. I would like to turn the meeting back over to you Mr. Evans.

Derek Evans

Thank you, Valerie. And thank you ladies and gentlemen for joining us on this call this morning. Just to reiterate, we remain quite excited about both our non-thermal and our thermal opportunities. And look forward to updating you on our continued progress on both of those fronts, as well as our GLJ reserve evaluation at our Annual General Meeting on June 24, 2014. Thank you very much for your time this morning.

Operator

Thank you. The conference has now ended. Please disconnect your lines at this time. And we thank you for your participation.

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