Enerplus Corp (ERF) 2016 Q1 法說會逐字稿

Good morning. My name is Jonathan, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation 2016 first-quarter results conference call.

(Operator Instructions)

Thank you, Mr. Drew Mair, Manager of Investor Relations, you may begin your conference.

Thank you, operator, and good morning, everyone. Thank you for joining the call.

Before we get started, please take note of the advisories located at the end of today's news release. These advisories describe the forward-looking information, non-GAAP information, and oil and gas terms referenced today, as well as the risk factors and assumptions relevant to this discussion. Our financials have been prepared in accordance with US GAAP. All discussion of production volumes today are on a gross company working interest basis, and all financial figures are in Canadian dollars, unless otherwise specified.

I'm here this morning with Ian Dundas, our President and Chief Executive Officer; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President Operations; and Eric Le Dain, Senior Vice President, Corporate Development and Commercial. Following our discussion, we'll open up the call for questions.

With that, I will now turn the call over to Ian.

Good morning, everyone. Our results released this morning demonstrate the continued execution of our strategy. We delivered on our production targets, continued to make meaningful progress on reducing costs, and further strengthened our balance sheet.

Production during the quarter was approximately 97,900 BOE per day, including 45,000 barrels per day of crude oil and natural gas liquids. We continued to see outperformance from our North Dakota wells, along with strong production results from our Canadian oil portfolio. We continue to expect full-year average production to be within our guided range of 90,000 to 94,000 BOE per day. This guidance is unchanged, despite the recently announced divestment of 2,300 BOE per day.

I will briefly recap our divestment activity. During the first-quarter, we announced and completed transactions with associated production of 5,400 BOE per day, generating net proceeds of CAD188 million. In April, we announced another non-core divestment with associated production of 2,300 BOE per day, for expected proceeds of approximately CAD95 million. We expect this transaction to close during the second quarter.

These divestments have improved the focus and quality of our portfolio, and strengthened our balance sheet. In addition, they have helped to deliver meaningful cost reduction. We've worked hard to reduce our cost structures, and we are seeing a material impact.

As the result of reductions to our operating, G&A and transportation expenses, we are reducing our 2016 cost guidance by CAD1.30 per BOE. Under current pricing, we continue to expect to balance our capital spending and our dividends with 2016 funds flow, as we focus on maintaining financial flexibility.

And with that overview, I will now ask Jodi to comment on our financial highlights.

Sure. Thanks, Ian. Our strong focus on cost reductions and efficiencies resulted in first quarter operating expenses of CAD8.15 per BOE, which were 6% lower than the fourth quarter of 2015, and 16% lower than the same quarter last year. The impact of numerous cost reduction initiatives, high grading of repair and maintenance activity, and the divestments of Canadian properties with higher operating costs throughout 2015, all contributed to lower operating expenses during the quarter.

Going forward, we expect the strengthening Canadian dollar relative to our US dollar operating costs, and the recently announced divestment of higher cost assets in Northwest Alberta to continue to drive operating expenses lower. As a result, we are reducing our 2016 annual OpEx guidance from CAD9.50 per BOE to CAD8.50 per BOE.

G&A is another area where we are seeing material cost reduction. We've had to make the extremely difficult, but necessary decisions to reduce our workforce in response to the challenging commodity price environment, and to align with our more focused asset base. As result, our first quarter G&A expenses were CAD2.07 per BOE, down 12% from the same period in 2015. However, this was up 18% from the fourth quarter of 2015, largely due to one-time severance payments incurred in the first quarter.

Given the almost 30% reduction in our workforce over the last 16 months, we expect G&A to continue to trend down, and are reducing our 2016 guidance for cash G&A expenses to CAD2 per BOE, from CAD2.10 per BOE. We are also reducing our transportation cost guidance to CAD3.10 per BOE from CAD3.30 per BOE, largely as result of the strengthening Canadian dollar. When you add this all up, we have reduced our cost guidance by CAD1.30 per BOE.

Funds flow for the first quarter was CAD42 million or CAD0.20 per share, down 60% from the previous quarter, as result of the significant reduction in crude oil prices and less hedging gains. We ended the quarter with total debt net of cash of CAD993 million, a reduction of CAD223 million from December 31, 2015. This decrease was primarily a result of applying the proceeds from our Deep Basin asset sale against outstanding debt, as well as the impact of the strengthening Canadian dollar, relative to our US dollar senior notes.

We used our divestment proceeds along with our largely undrawn bank credit facility to fund the repurchase of $172 million of our senior notes during the quarter, and a total of $267 million of senior notes to date. The repurchases were completed at prices ranging from 90% of par to par value, with no penalty or make-whole payments required, for a total gain of CAD19 million to date.

The success we have realized on our senior note repurchase program has provided additional flexibility within our capital structure, as it has allowed us to use divestment proceeds to repay outstanding debt, which we otherwise wouldn't have been able to do, given we have no scheduled principal repayments until June 2017. Furthermore, we expect to save approximately $13 million in interest expense on an annualized basis, for approximately [CAD]0.50 per BOE, as a result of replacing fixed term higher interest rate debt, with our lower interest rate bank debt, and using divestment proceeds to repay this outstanding debt.

At quarter end, our debt to trailing 12 month funds flow ratio was 2.3 times, and debt to trailing 12 month EBITDA ratio was 1.6 times. The difference in our EBITDA ratio compared to our funds flow ratio was due to gains of CAD145 million on our Deep Basin asset sale, and CAD7 million on our senior notes repurchased during the quarter.

Additionally, it is important to note that our debt outstanding at March 31, does not include the proceeds from our recently announced divestment of Northwest Alberta assets for CAD95.5 million. We expect this transaction to close late in the second quarter, and we'll use the proceeds to further reduce outstanding debt. We expect to realize a gain of approximately CAD70 million in the second quarter related to this divestment.

I will now turn the call over to Ray to speak about operations.

Thanks, Jodi. Capital activity in the quarter was largely focused in North Dakota and our Canadian waterflood portfolio. In North Dakota, we drilled 4.4 net wells, and brought 2 operated wells on stream.

We drilled a long well in record time, in Fort Berthold, taking just 12.2 days from spud to TD. This beat our previous best by 2.8 days, and was 4.3 days better than our AFE. The final drilling cost estimate for that well is $2.8 million, about $600,000 below the AFE estimate of $3.4 million, a savings of approximately 18%.

The two operated wells that we brought onstream in the quarter had an average initial 30 day production rate of 1,870 barrels of oil equivalent per day, 28% above the type curve for the area. Subsequent to the quarter, we brought two more operated wells onstream, which have averaged more than 2,000 barrels of oil equivalent per day, and they're for 30 days. Again, above their type curve, this time by about 18%. We continue to make changes to our drilling, completions and facility design to maximize capital efficiency.

Regarding costs, we've targeted savings on water purchased, transportation and disposal. This brought our completions cost down a further $300,000 from 2015, to a total of $4.5 million inclusive of water hauling and disposal. We applied different technologies to our completion design, to stimulate more rock volume, and maintain sand pack concentration.

We continue to develop our facilities modular construction approach, and along with more efficient on-site logistics, we have reduced our facilities cost a further15% from 2015. All-in, our current well costs are now approximately $8.5 million including facilities, and we are retaining or beating our expected IP performance.

At the end of the quarter, we had approximately 11 drilled uncompleted wells in Fort Berthold, and expect that number to remain relatively flat to year-end. In Canada, we drilled four producers and three injector wells across our waterflood portfolio. Operations were focused Cadogan, Giltedge, and southeast Saskatchewan. Overall, the program in Canada was delivered on time and on budget, with well results meeting or exceeding expectations. For the remainder of 2016, capital activity in Canada will be largely focused on performance and cost optimization work.

Turning briefly to the Marcellus. Activity levels continue to be low, pending further improvement in regional pricing. We continue to forecast full-year spending to be approximately CAD20 million.

At the end of Q1, we had approximately eight net DUCs in the Marcellus, and given the limited drilling activity, we do not see this building throughout the year. Jodi talked about the reduction in our operating costs, from the combined influence of exchange rate, divestment and cost reductions. However, I would like to highlight the tremendous work our field and office staff in Canada and the US, have put in taking accountability for every penny of operating costs spent and the compounding benefit of that commitment is showing up on the bottom line.

And with that, I will pass the call to Eric to speak about pricing and our hedging program.

Thank you, Ray. I will touch briefly on Bakken and Marcellus pricing, and then provide an update on our hedging activities. Our US Bakken realized differential at aggregate of the field sales points averaged $8.38 per barrel during the first quarter, before field transportation. We continue to forecast a tightening differential over the year, as industry production declines, and expect an average differential of approximately $7 per barrel in 2016.

Our realized Marcellus gas pricing in the first quarter of averaged $0.91 per Mcf below NYMEX. This was an improvement of approximately 20% from the fourth quarter, and over 40% from the third quarter of 2015, as a significant reduction in industry spending in the region has slowed production growth. We continue to guide to a basis differential of $1 per Mcf below NYMEX for our 2016 Marcellus production. Despite the improving basis differential, Enerplus is still forecasting some production curtailment, in the event of low NYMEX prices.

Turning to hedging, we've added price protection in 2017, on both our crude oil and natural gas production. For both commodities, we believe prices are likely to rise in 2017, so we want to retain some of the upside on hedged volumes, but we also need and want to protect our project economics and funds flow. For crude oil, we entered into three-way collar structures of approximately $36 per barrel, by $48 per barrel, by $60 per barrel for 6,000 barrels per day of production for 2017.

For natural gas, in the quarter, we entered into three-way collar structures of approximately $2 by $2.70 by $3.30 per Mcf for 35 million cubic feet a day for 2017 production. Overall, we now have a combination of crude oil swaps and collars in 2016 for 31%, and collars in 2017 for 20% of forecast net production after royalties. For natural gas, we have a combination of swaps and collars in 2016 for 31%, and collars in 2017 for 16% of forecast net production after royalties.

You will recall, we also have 80 million cubic feet a day of fixed [ACO] basis physically hedged at $0.65 per MMBtu for the next three years. We have also had a similar position in 2016, and have locked in some of the value from this position already. Please refer to our news release or MD&A for details, further details on our hedge portfolio.

And now back to Ian for some closing remarks.

Thanks, Eric. Recapping the highlights of the quarter, strong production performance has allowed us to remain within our production guidance range, despite the additional divestments. We have reduced debt by over CAD220 million. We are reducing 2016 cash cost guidance by CAD1.30 per BOE.

In addition, we have reduced our interest expense by 20% to 25% on an annualized basis, which equates to further savings of approximately CAD0.50 per BOE. Our debt to funds flow ratio stood at 2.3 times, and debt to EBITDA at 1.6 times at the end of Q1, and we continue to achieve our safety and social responsibility objectives.

In summary, our strategy is on track, and execution is strong. We continue to successfully navigate through this volatile market, having made key improvements to our cost structures, and improvements to our balance sheet. And we remain well-positioned to reestablish growth and market conditions improve.

And with that, I will now turn the call over to the operator, and we are here to answer your questions.

(Operator Instructions)

Mr. Mair, there are no questions at this time.

Well, as my dad always said, never look a gift horse in the mouth. Thank you very much for your attention, and we will wrap up the call with that. Thank you. Have a good day.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.