Obsidian Energy Ltd (OBE) 2013 Q1 法說會逐字稿

Good morning, my name is Adrian and I will be your conference operator today. At this time, I would like to welcome everyone to Penn West Petroleum's 2013 first quarter results. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

Thank you. Mr. Clayton Paradis, you may begin your conference.

Thank you, Adrian, and good morning, everyone. Welcome to Penn West's 2013 first quarter financial and operating results conference call. With me this morning in Calgary is our President and Chief Executive Officer, Murray Nunns; Chief Financial Officer Todd Takeyasu; Executive Vice President of Operations/Engineering, Dave Middleton; Senior Vice President, Development, Mark Fitzgerald; and Senior Vice President, Exploration, Mr. Rob Wollmann.

Before getting started this morning, I would like to quickly remind listeners of our customary advisories. Penn West Exploration shares trade on both the New York Stock Exchange under the symbol PWE, and on the Toronto Stock Exchange under the symbol PWT. All references during this conference equal are in Canadian dollars unless otherwise indicated and all conversions of natural gas to barrels of oil equivalent are done on a 6 to 1 conversion ratio. All financials are reported under International Financial Reporting Standards, or IFRS.

Certain information regarding Penn West and the transactions and results discussed during this conference call, including management's assessment of future plans and operations may constitute forward-looking statements under applicable securities laws and necessarily involve risks. Official information detailing other risk factors that could affect Penn West operations or financial results are included in reports on file with Canadian and US security regulatory authorities and may be accessed through the Sedar website at www.sedar.com and the SEC website at www.sec.gov or on Penn West's website. During this conference call, certain references to non-GAAP terms may be made and participants are directed to Penn West's MD&A and financial statements available on our website, as well as filings available on other websites noted earlier to review disclosure concerning non-GAAP items. I would like to turn the call over to Mr. Murray Nunns, President and Chief Executive Officer.

Thanks, Clayton, and good morning, everybody. First off, Penn West continues to evolve, it has been part of what we have had to do for 23 years-plus or 21 years-plus. As part of the evolution, Mr. John Brussa has stepped down as Chairman and from the Board of the Company. Since John's appointment to the Board in 1995 and subsequent appointment as Chairman of the Board in 2005 his counsel and advice has served Penn West and its shareholders well. I would like to personally thank John for his significant contributions to Penn West.

Mr. Jack Schanck, a member of Penn West's Board since 2008 has been appointed Chairman as part of the Board renewal process. Jack brings over 37 years of experience in the oil and natural gas industry as both a senior executive and geologist. He was Co-Chief Executive Officer of Samson Investment Company, a large private oil and natural gas company based in the US, and held a variety of positions over a 23-year period with Unocol Corporation including President of Spirit Energy, the domestic E&P division of Unocol and President of Unocol Canada.

Penn West has one of the largest portfolios of fully appraised light oil resources in North America. As we progressed through 2012, it became apparent to us that as we moved from play appraisal to development, we were not maximizing the returns from our assets. We recognized this and have made changes both organizationally and operationally. Our 2013 corporate objectives were created to focus performance. Goal number one, capital efficiency targeting CAD35,000 to CAD40,000 per BOE per day. Goal number two, increasing production reliability and performance, and goal number three, continuing to improve the balance sheet.

Achieving these goals is important in demonstrating the inherent value of the Company, having its value recognized in the market, and in setting long-term direction of the Company. In support of these objectives, we changed how we do business. On the operational side, we moved to integrated cross-functional business districts from a functional structure. With the teams now well established, goal alignment is perfectly clear and compensation for everyone is tied to meeting those goals. Our first quarter performance provides evidence that these changes are bearing positive results.

Average production for the first quarter of 2013 was 142,800 BOE per day driven by improved production reliability and significant improvements in capital efficiency. Annual 2013 production guidance remains unchanged at 135,000 to 145,000 BOE per day. On the capital efficiency objective, focusing capital on fewer light oil areas and driving to reduce drilling and completion costs across all core light oil regions has resulted in positive outcomes. Across all regions, improvements in well and pipeline repair, maintenance cycle times, all contributed to stronger production performance. Cost structure improvements, increased reliability on base production and focused capital allocation gives us a high degree of confidence that Penn West is on track to hit its capital efficiency target of CAD35,000 to CAD40,000 per flowing barrel as outlined in the 2103 capital budget. We will do a little bit more on these operational improvements a bit later in the talk with Rob Wollmann.

And I really want to underscore this. We are not finished on organizational and executional improvements. We are continuing to tighten the ship, we are enhancing production operations in the field. We are refining our second half capital allocation and striving to realize further improvements on the cost structure. Staff has also been reduced by 10% since the fall of 2012. This is an on going process as we focus on improving G&A costs corporately.

In the fall of 2012, the existing executive team committed to and has been effective in initiating organizational and operational change at Penn West as evidenced by our performance in the first quarter. The right candidate for COO will complement these changes. The search for a COO is ongoing with several high-caliber candidates identified. We anticipate completing the search process by this summer.

Now moving on to the financial results, funds flow for the first quarter CAD267 million, or CAD0.55 per share, which was ahead of the internal expectations, primarily due to higher than budgeted light oil price realizations. In the first quarter, we realized average price of over CAD80 a barrel for our light oil and NGL production. These light oil and NGL volumes represent 82% of the total liquids production of the Company and over 75% of our production revenue. Edmonton par to WTI light oil differentials averaged approximately CAD7 per barrel in Q1 compared to our internal expectations of CAD10 per barrel. Penn West has over 80% of its forecast 2013 oil production, net of royalties, hedged between $92 and $104 per barrel.

The Gulf Coast, in looking at transport and infrastructure, the Gulf Coast represents one of the largest global refining regions for light oil and heavy crudes. To ensure strong pricing for our light production and our 16,000 barrels of heavy crude, Penn West has contracted 35,000 barrels a day transportation capacity on the Flanagan South pipeline to the Gulf Coast beginning in the second half of 2014. This will be an important market for Penn West. Penn West is also selectively shipping crude by rail in certain areas and expects to reach the 5,000 to 7,000-barrel a day range in the second half of 2013.

With regards to the dividend, the Board of Penn West has declared the second quarter dividend in the amount of CAD0.27 per share to be paid July 15, 2013 to shareholders of record on June 28, 2013. Penn West production is on plan, capital is on budget and cash flow is ahead of budget. Penn West had a solid first quarter and it's a good data point. We've demonstrated progress and we now look to establish these performance levels as a long-term trend. Our aim is to continue to demonstrate the performance so that it is clear to the investment community. I will now turn the call over to Rob Wollmann, Senior VP of Exploration, whose shared responsibility with the senior management team is to deliver on the dollars, the barrels and time.

Thank you, Murray. In the first quarter, production at just under 143,000 BOEs a day is on target. Capital expenditures of CAD427 million were on budget. Anticipated drilling and completion cost savings were realized. All plan, development activity executed. New wells were brought on stream on schedule and execution of our base production reliability initiatives are on plan.

Full year 2013 capital guidance remains CAD900 million. Significant strides along the path towards improved operational performance were made. Our facilities and production groups have worked effectively together improving base production reliability to 91% to 92%, well above last year when reliability fell to as low as 88%. Focus has returned to ensuring unscheduled down time, whether due to downhole mechanical issues, pipeline infrastructure, work facility upsets is dealt with quickly and cost effectively. Scheduled maintenance projects have been executed on or under expected cycle time and on budget. We've budgeted for and invested incremental capital dollars in the base and this has resulted in improved reliability. Operating costs in Q1 were on budget. Initiatives such as infrastructure consolidation in older fields are being implemented to reduce operating costs in the future.

119 development wells were drilled in the quarter, 58 of which were in the Spearfish. The new natural gas liquids extraction plant has came on stream on budget as planned in April. Compared to last year, drilling times in the Spearfish, as defined by spud to rig release, dropped from an average of eight days down to five, a result of improved drilling engineering procedures, a fit for purpose rig fleet and focused, well understood execution plan. Average drilling and completion costs were CAD1.2 million per well, a savings of approximately CAD150,000 per well versus last year's program. Despite the extreme cold weather experienced in southwest Manitoba in midwinter, all planned wells were drilled, completed and tied in on schedule with all field activity wrapped up in March, well before breakup. Going forward, as the infrastructure is filled to capacity, focus in the Spearfish will be on its long-term sustainability, maintenance of reservoir pressure, and the drilling of sufficient wells to maintain production levels.

In the Slave Point and Swan Hills Carbonate trends, winter activity focused on capitalizing on the strong 2012 wells productivity results at Sawn and East Swan Hills while decreasing the cost structures in spud to on stream cycle times. At Sawn, two high quality rigs and experienced crews employing improved drilling procedures completed the eight wells horizontal single lateral program in early February, ahead of schedule. Average drill days dropped from 28 days per well last year to below 20 days this year. Drilling and completion costs dropped from CAD6.7 million per well to CAD4.8 million. Productivity of the original Sawn single laterals in the new development area, drilled in 2011 and 2012, remain strong with current daily rates ranging between 75 barrels and 300 barrels of light sweet crude after 9 to 24 months of production. This winter six wells came on stream in late April. Initial cleanup in production to just these wells will have similar strong productivity to the 2011 and 2012 horizontals.

Horizontal water flood is anticipated to further enhance long-term recoveries in overall economics at Sawn. Reservoir simulations estimate incremental oil recovery factors of 5% to 10% on top of primary. Our initial horizontal water flood is scheduled to be operational by year end. Full scale integrated horizontal primary and water flood development will be rolled out over the next several years as we develop this top quality asset. Water flood in combination with the lower drilling completion costs, the expanded infrastructure and the strong average productivity drives the economics of light oil development at Sawn to be some of the strongest in the Company. In the Swan Hills, winter activity focused on selective redevelopment and extension of this conventional light oil play. Drilling times, which averaged 29 days in 2011 and 16 days last winter, fell to 14 days in the first quarter as the benefits of improved drilling practices and the use of the same rig in the same area for several years demonstrated efficiency gains.

Per well drilling and completion costs year over year dropped from CAD5.2 million to CAD4.3 million. Our [10 of 32] battery turnaround, originally scheduled last year, with three weeks of downtime and an CAD18 million price tag was completed in four days for under CAD5 million. The integrated field and Calgary team redefined and reset the requirements and executed the turnaround, minimizing downtime and reducing costs. In the Viking, 27 wells were drilled in the quarter. Drilling completion costs remained flat year over year.

Our costs in the Viking remains higher than industry average but for good reason. We invest more in completions than our competitors. Our wells on average over the first 12 months are 33% more productive and exiting the first year 40% more productive on a daily basis. Cardium activity in Q1 was modest with six wells drilled in the Alder Flats area. Drilling and completion costs dropped from CAD3.3 million per well last year to CAD2 million, a result of improved drilling times down to just over 7 days, spud to rig release, and substantially lower completion costs due to the adoption of water-based fracks in an area which historically had been fracked with oil.

The horizontal water flood pilot at West Pembina continues to meet expectations. Low decline oil production has increased with minimal water cuts observed to date. Two additional water floods at Willesden Green are scheduled to come on stream prior to year end. Development of the Cardium light oil resource is anticipated to accelerate in 2014 as large scale integrated development plans are finalized.

Across all of our core light oil plays, costs and cycle times are now competitive with leading industry operators, an important step in maximizing the value of our resource plays. Our early light resource assets, the Cordova joint venture, the Peace River Oil joint venture, and our significant Duvernay shale position continue to evolve. Cordova focus has been on develop tactics to improve drilling completion cost structure and assessing the most economic well bore spacing. Drilling is scheduled to restart in Cordova in the third quarter. First quarter Peace River activity focused on primary multi lake horizontals, construction of the three-well Harmon Valley South thermal pilot scheduled to come on stream later this year, second cycle production at the Seal Main thermal pilot, and working through the regulatory requirements for the 10,000-barrel-per-day Seal Main commercial thermal project.

High value deep asset base requires some clear portfolio decisions. Our Duvernay position at Willesden Green is clearly well situated in a liquids rich fairway. We have initiated a joint venture divestiture process on the Duvernay to bring forward value and improve the Company's balance sheet. We will not be providing any additional color on potential initiation.

Q2 production and outlook, we have achieved cost savings in the first quarter on drilling and completions, completing our winter program prior to breakup. Drilling activity is expected to recommence in July. In January, we laid out a series of conditions related to an incremental capital expenditure of up to CAD300 million. Those were sustained realized prices at or above budget levels, demonstration of improved capital efficiencies, improvement of the balance sheet through ongoing portfolio rationalization and Board approval. When we have solid checkmarks for all conditions we will decide on a recommendation to our Board on expanding the capital budget, but not yet. Production in the second quarter will be impacted by planned turnarounds and spring breakup. We have budgeted those effects to have a 4,000 to 5,000 BOE per day quarterly impact.

Operated and non-operated facility turnarounds, scheduled in the second and third quarter, are expected to reach a peak production impact of 10,000 barrels per day in June. These planned turnarounds are included in our annual production guidance. The risk to our operations of spring breakup, though minimized through the construction of improved drainage ditches, elevated leases, and group gathering pipelines still exists for temporary production losses depending on the magnitude of flooding and other breakup conditions.

Full field integrated development planning is underway across our opportunity base. We will continue to be very selective in capital allocation, targeting projects with low capital efficiencies that deliver an all-in a minimum 20% rate of return and which maximize long-term value creation. I would like to turn this call over to the operator and open up the phone line for callers.

(Operator Instructions)

Your first question comes from the line of Cristina Lopez from Macquarie. Your line is open.

Hi, gentlemen, just a few quick questions. One, with respect to asset sales outside of the Duvernay -- how are those progressing? Are you giving any sort of target as to the potential amount of divestitures you would like to complete this year?

I will turn that question to Mark Fitzgerald here.

Yes, Cristina, it's Mark. Rob talked about the Duvernay. I think as an overall strategy, we have been very clear about looking at disposition opportunities to reduce the debt. Having said that, part two of that becomes ensuring that we are selective in moving base assets outside the Company, ultimately minimizing the cash flow impact on the Company, improving profitability on the back end.

There certainly has been indicative interest. We continue to move on various tasks in analyzing and looking at what we could move out. But as I highlighted, we will be selective in where opportunities make sense for us to do so; then we will transact on those base assets.

So, Cristina, overall, there is no single set target. We are going to push the early-life assets first. We will look at base assets selectively, but only on high cash flow multiples. We are not just going to trade out cash flow and have to drill volume back later on.

Excellent. Thank you. And then, you mentioned that the peak impact of turnaround of 10,000 BOEs a day is going to occur in June. Does any of that roll over into July into your Q3 numbers?

Yes, for a couple of weeks there, the turnarounds will extend into Q3. It will impact the first two or three weeks of Q3.

And, now, your criteria for -- with 47% of the budget spent on your CAD900 million outlook -- kind of a couple -- two-part question here. One is what the profile for spending for the remainder of the year would look like? And the second one is, of your four criteria, one is an improved balance sheet. Is it a debt-to-cash-flow target, and if so, what debt-to-cash-flow target are you looking at in order to determine if you should increase that budget to the CAD1.3 billion?

Sure. I will break that kind of into two parts, that question. First, on the 47% of our spending -- we did spend about CAD425 million, plus or minus, in the first quarter. Just in profiling the impacts of that, we had about -- we tied in roughly 60% of what we drilled in the first quarter. It was very much late in the first quarter -- later in the first quarter, and very much consisted of the shallower component of our activities. So the other 40% of that capital really will impact throughout second quarter and third quarter, depending on when we finish the tie-ins and bring on-stream some of the deeper wells from the first-quarter program. So the impacts of the balance of that first-quarter capital will be felt throughout the second quarter.

Now, we are not going to rush that. We are not going to push ourselves through the mud to get these tie-ins done. We are going to do them at the most cost-effective times.

The spending in second quarter we suspect is really confined to spill-over tie-ins from the first quarter, and tie-ins throughout the second quarter without much active drilling. In fact, I think we plan virtually zero drilling in the second quarter under the current call. So that then sets up for looking at the extra CAD300 million.

As a minimum, I would say we are -- at the end of the day, would not be looking to have a debt-to-cash-flow higher than 2.5, but I think our target is significantly lower than that. And as for engaging the CAD300 million, obviously, critical to that is seeing the commodity prices, as well as retiring some debt before we would engage that CAD300 million. So I don't think we will be making a call much before, or even before, the next quarter release.

And then the last component is the dividend -- obviously, a dividend cut could get you that incremental capital pretty quickly, as well. Can you speak to what your view is on the dividend through the second half of the year with the dividend, obviously, set for the second quarter?

I will say -- we have an ongoing strategic discussion with the Board, basically a continuous discussion on this basis. I believe we will leave that discussion ongoing. I'm not going to give an indication one way or another. We have been fairly consistent. I think -- so before we make any call, this will be a Board decision, and it will weigh up our performance as an entity. We are not going to extend that beyond that general discussion with the Board.

Excellent. That's all for me. Thank you, guys.

Your next question comes from the line of Kyle Preston of the National Bank. Your line is open.

Yes, thanks, guys. I'm just wondering if we can get a little more color on these cost improvements you have seen on your drilling program, in particular the Cardium -- you have seen a big improvement there, 35% improvement at Alder Flats there. Just wondering, again, what the real key drivers were there? Also, if you think you will be able to carry these cost savings into other areas of the Pembina play there? And also what you'd expect to happen once you start to ramp up development more aggressively in this play?

Hi, Kyle, it's Rob Wollmann. In specific in the Cardium, what made the changes? Drilling days dropped about two to three days on average per well. That certainly contributed to some incremental cost savings. So the main, real driver was changing from oil-based fracks to water-based fracks. That by itself has saved on average between CAD750,000 and CAD1 million per well on the completions. That has been the significant driver there.

With respect to having those savings seen across the Cardium play, quite frankly, that is critically why we haven't been as active in Q1 in the Cardium as we could be. We wanted to make sure that we realized the savings that we planned for. We used Alder Flats as sort of the proxy. Now we're developing the longer-term plans in the broader part of the Cardium portfolio prior to -- and with the expectation of it achieving similar savings across it. So use a proxy for the whole play, ensure that you are seeing those savings, and then be more confident in applying it across the whole area.

And when would you look to start ramping up the development there?

I think realistically we are looking 2014. Clearly, with the evidence that we have got from our water flood pilot, it won't just be a primary drilling project. It will be an integrated primary and water flood project that will look at the Cardium component, and focus on select components within the Cardium, and develop those fully.

All right, thank you.

(Operator Instructions)

Your next question comes from the line of Brian Kristjansen from Dundee Capital Markets. Your line is open.

Good morning, guys. Just following on Cristina's question. I'm not sure if you can give more detail with respect to those CapEx profile, or what you are budgeting for Q2 production?

I think Rob had outlined -- first, I'll tackle the Q2 production, and then maybe turn it to Mark in terms of the profiling of the capital for the balance of the year. On the Q2 production, we anticipate the impact of, again, turnaround -- turnarounds and break-up to impact us to an average effect of between 4,000 to 5,000 barrels. I think looking roughly at Q1 levels, and looking towards that range of impact, and again, we're being relatively conservative in our projection of when we bring on Q2 volumes. So I think if you can tie those points together, that would be the way to think about Q2 volumes.

Then, in terms of capital, I will turn it to Mark Fitzgerald to comment on the capital spending profile for the balance of the year.

Sure. Thanks, Murray. Brian, Murray and Rob both talked about what we did in Q1, which was very aggressive drilling early on. We had wells come on through March, into the end of March, and have made a very concerted effort to avoid activity as we move into breakup, and ultimately as we see conditions in Q2 that are -- I would suggest not the most efficient way to conduct our operations. So Q2 for us is going to be quiet on the drilling rig, it will be on the drilling side, as Rob has highlighted, will be focused on bringing wells on stream that we drilled in the first quarter. And then as conditions improve, you will see us start to be active again on the drilling side, likely through the end of June into July, as we are able.

That would imply then a profile that, again, very busy in the first quarter on drilling completions and bringing a portion of those wells on through the end of March, a focus in the second quarter on bringing what we can efficiently on stream through that period, and then starting to ramp in dry conditions in the summer again with the drilling rigs for the balance of the year. It is a measured approach in 2013. It's, as we've said, very focused on ensuring that we are highly efficient with our capital, that we avoid time periods where playing in the mud, so to speak, increases cost and reduces our efficiency, and you will see us move into the second half as those conditions allow.

One other thing I would add to Mark's comments -- as we move through the summer program, you will probably see a few less rigs operating. We will start rotating towards some of the deeper plays; I think you will see a little bit more on the Slave and the Cardium, and we'll be lightening up on some of the shallower ones. That will spread the capital out a bit more -- spread the drilling program out a bit more, and you will see a few less rigs through Q3, but extending into Q4.

I'm assuming more Q4 weighted then, on the second half?

I think in terms of seeing when the volume adds, they will be into Q4. The spending, more in Q3.

Okay. Thanks, guys.

Your next question comes from the line of Roger Serin of TD Securities. Your line is open.

Thank you very much; all of my questions have been answered.

That's fine, Roger, thank you.

There are no further questions at this time. I will turn the call back over to the presenter -- pardon the interruption. There is one more question from Gordon Tait of BMO Capital Markets. Your line is open.

Good morning. I was just wondering -- you talked about some of the organizational changes you made going from functional lines to more geographic areas within the Company. Can you tell us specifically what that resulted -- how those changes result, or what have they done to improve specifically some of the problems that you were having?

Yes, Gordon, good question. I will just maybe reframe a little bit of it. The geographic units in and of themselves just provide the umbrellas. But the key was integrated teams, so that basically we have gone to complete physical integration of all the disciplines, from geologic all the way through the spectrum. So that was the first thing.

Where we had had in the past trouble was we had functional groups with their individual goals, and not aligning up under a common set of goals. So a common set of goals and an integrated approach to the Business. Nothing getting dropped in the hand-offs overall led to better planning, better execution, so that we were delivering what we anticipated at the right cost, on time. It was the combination, again -- alignment to the common goals and physical integration of these teams, and working towards those common goals. That has really made the difference. And the areas where we had had execution issues, I -- hopefully, we have been able to document today that we have changed the direction of the way we operate as an organization.

So for instance, were some of those execution issues something like you would have wells drilled but no facility available for them?

I would say that we've had those kind of examples in the past. We are not having them now. And I would give another example. I really want to actually extend -- I will do a little bit of a shout out to our -- both our production and our facilities groups. They have taken our load of volumes that were off stream, and taken our cycle times and cut them in half.

So when a well comes off, it gets repaired. When a facility comes off, it gets repaired, and gets repaired quickly. This was an area where we had a significant gap. We do not have a gap now. The asset base is now performing at a standard that is up to our expectations, and is at, or in excess of, industry standards for these types of assets.

And then within these geographic groups, they are competing for capital, I presume? Do you measure the performance of returns within the geographic group to see if they met or exceeded those guidelines?

Absolutely, Gordon. The competition for capital is fierce, as we have constrained capital. We have [hydrated] the portfolio on allocation. The review cycle time on these projects is weekly. They are coming into the senior table from each district.

If there is any deviation from plan, there is explanation on the table as to why. That's part one. And part two -- any innovation or change is spread across the Company very quickly. So, all of this -- change to integrated model and a higher level of accountability that we have held everyone to is paying off.

Then last question -- with the change in the Board Chair, could we expect to see any other changes in the Board, and does it signal maybe a change in direction or strategy for the Company?

What I would say is -- this is -- Gordon, this was one step in part of a Board renewal. And the Board is looking at that, obviously. More of that will become self evident as we move through the AGM cycle.

I know that part of the ongoing discussion will be the future direction of the Company. We, obviously, said from the outset that we have got to get our internal performance right in terms of cap efficiency and production, we've got to get the balance sheet right before any decisions of that type are made, so that discussion will be ongoing with the new Board.

All right. Thanks.

Thanks, Gordon.

This concludes our question-and-answer session today. I will turn the call back over to the presenters.

Thank you, everybody, for your time and attention today. We have set out to do some things at Penn West to maximize the value that we can extract from our entire resource base. We have made some significant strides on that front, and we are going to be continued to be focused on exactly that. Thank you, everyone.

This concludes today's conference call. You may now disconnect.