Enerplus Announces Strong 2015 Results; Low Cost Reserves Additions and Reduced 2016 Budget and Dividend

CALGARY, Feb. 19, 2016 /CNW/ – Enerplus Corporation (“Enerplus” or the “Company”) (TSX: ERF) (NYSE: ERF) is pleased to announce its results for the fourth quarter of 2015 as well as full year 2015 operating, financial and reserves results.  Enerplus is also updating its capital budget and production forecast for 2016 and is reducing its monthly dividend.

“Despite the commodity price headwinds in 2015, we delivered an exceptionally strong year of operational performance while maintaining our financial flexibility and continuing to improve the focus of our portfolio,” said Ian C. Dundas, President and CEO of Enerplus. “We continued to focus our capital program on our core position in North Dakota where we delivered 28% production growth during 2015 under a disciplined and paced development strategy.  Our ongoing commitment to reducing our cost structure helped us realize operating and G&A costs below our targets and competitive F&D costs at $8.44 per BOE.”

FINANCIAL AND OPERATIONAL HIGHLIGHTS

• Enerplus delivered fourth quarter production of 106,905 BOE per day, contributing to annual average production of 106,524 BOE per day, approximately 3% higher than 2014 and above guidance of 106,000 BOE per day. This strong production was despite a 39% reduction in capital spending year-over-year and over 6,000 BOE per day of production divested during the year which, given the timing of the divestments, reduced annual average volumes by approximately 1,300 BOE per day.
• Crude oil and natural gas liquids production also exceeded guidance, averaging 46,227 barrels per day in the fourth quarter and 46,402 barrels per day in 2015. This represents liquids production growth of approximately 6% over 2014. The higher liquids production is attributed to strong production growth in North Dakota which averaged approximately 27,700 BOE per day during 2015, up 28% from 2014.
• Enerplus exceeded its production targets despite lower than budgeted capital spending of $89 million in the fourth quarter, as a result of continued well outperformance and further cost savings. Full year capital spending was $493 million, below guidance of $510 million. Enerplus allocated 85% of its 2015 capital program to its oil portfolio in North Dakota and the Canadian waterfloods. Enerplus drilled 1.8 net wells and brought 6.2 net wells on-stream in the fourth quarter, and drilled 46 net wells and brought 57 net wells on-stream during the full year 2015.
• Fourth quarter funds flow was $103 million ($0.50 per share), down approximately 15% from the previous quarter primarily as a result of lower commodity prices and production volumes. Full year funds flow was $493 million ($2.39 per share), down approximately 43% primarily due to significantly lower crude oil and natural gas prices relative to 2014. Commodity hedging helped support funds flow during 2015 with cash gains of $288 million.
• Continued improvement in Enerplus’ cost structure resulted in both 2015 operating costs and G&A costs lower than guidance. Fourth quarter and full-year 2015 operating costs of $8.71 per BOE and $8.76 per BOE, were 10% and 5% lower than comparable periods in 2014, respectively. Fourth quarter and full-year 2015 G&A costs of $1.75 per BOE and $2.09 per BOE, were 33% and 6% lower than comparable periods in 2014, respectively. Reduced capital activity and divestments throughout the year resulted in Enerplus rationalizing its operations and reducing its workforce by approximately 20% which, along with ongoing cost savings initiatives, contributed to the lower G&A costs.
• Enerplus reported a net loss of $625 million in the fourth quarter as it incurred non-cash charges including $266 million related to an asset impairment and a $426 million valuation allowance for deferred tax assets. Under U.S. GAAP, Enerplus is required to use twelve month trailing average prices to determine impairment, and consequently the impairment reflects the low commodity prices throughout 2015. Enerplus reported a net loss for the full year of $1,523 million and impairment charges of $1,352 million. Under U.S. GAAP impairments are not reversed in future periods.
• Enerplus continues to maintain its financial flexibility through its ongoing reduction to cost structures, successful non-core asset sales and disciplined capital spending. Enerplus ended the year with total debt net of cash of $1,216 million, including 11% drawn on its $800 million bank credit facility. Year-end debt to funds flow ratio was 2.5 times and debt to EBITDA ratio was 2.2 times.
• In addition to divestments announced during 2015, Enerplus sold various non-core Canadian shallow gas assets located in southern Alberta in the fourth quarter. These were lower margin properties with dry gas production and higher operating costs than Enerplus’ corporate average, comprising approximately 2,300 gross shallow gas wells (1,700 net wells). This divestment reduced the Company’s Canadian well count by approximately 17%, and reduced its overall abandonment obligations by approximately 15%. The cash consideration for these assets was nominal. Production from these properties was approximately 2,700 BOE per day (99% natural gas). This divestment further improves the focus and concentration of Enerplus’ portfolio and is expected to improve the Company’s netback as a result of the higher relative operating costs of these assets and have a modest impact on funds flow.
• Subsequent to year-end, Enerplus announced two Deep Basin asset divestments for total proceeds of $193 million. The Company received proceeds of $183 million, before adjustments, on the closing of one sale in January 2016, and expects the second transaction to close during the first quarter of 2016. Proceeds have been used to repay Enerplus’ drawn bank credit facility as well as a portion of its outstanding senior notes which has further improved the Company’s liquidity position.

SELECTED FINANCIAL AND OPERATING RESULTS

2015 RESERVES HIGHLIGHTS

Enerplus delivered another year of strong reserves results in 2015:

• Replaced 108% of 2015 production, adding 42 MMBOE of proved plus probable (“2P”) reserves. Well performance in both North Dakota and the Marcellus continued to exceed the previous forecasts of Enerplus’ independent reserves engineers and resulted in significant positive technical revisions.
• Replaced 163% of 2015 crude oil and NGL production, adding 27 MMBOE of 2P crude oil and NGL reserves primarily from North Dakota. Crude oil and NGLs now comprise 51% of 2P reserves.
• 2P finding and development costs (“F&D”) decreased by 14% year-over-year to $8.44 per BOE, including future development costs (“FDC”). Enerplus’ three-year average 2P F&D is $10.10 per BOE. Proved producing F&D was $11.90 per BOE in 2015.
• Enerplus sold various properties representing 27 MMBOE of 2P reserves at a value of $13.36 per BOE. Total 2P reserves, net of divestments, were 406 MMBOE at year-end 2015, representing a 5% decrease from 2014.
• 2P finding, development and acquisition costs (“FD&A”) were $0.25 per BOE including FDC. Enerplus’ three-year average 2P FD&A is $7.76 per BOE.
• 2P reserves in North Dakota increased 17%, including positive technical revisions, to 144 MMBOE, at an F&D of $7.60 per BOE. Based on an average operating netback of $18.66 per BOE in 2015, this represents a recycle ratio of 2.5.
• Proved (“1P”) reserves continue to comprise a significant proportion of 2P reserves at 68%. Proved producing reserves represent 49% of 2P reserves.
• Strong reserves life index of 12.2 years, up from 10.7 years at year-end 2014, in part due to a lower production forecast given reduced levels of capital spending in the current low commodity price environment.
• Using the December 31, 2015 independent reserves evaluation, the net present value of Enerplus’ 2P reserves discounted at 10%, net of debt and asset retirement obligations and including undeveloped acreage value, is estimated to be $11.65 per share.

2016 OUTLOOK

In response to the continued decline in crude oil prices, Enerplus is taking further steps to protect its balance sheet and maintain its financial flexibility.  Enerplus’ Board of Directors has approved a reduction in the monthly dividend to $0.01 per share from $0.03 per share, effective with the April dividend, payable on April 15, 2016. This reduction reflects the need to rebalance the dividend level in the context of the sustained low commodity price environment.

Enerplus has also reduced its 2016 capital budget a further 43% to $200 million. This represents a 60% reduction from 2015 spending levels.  The reduced budget is focused on balance sheet preservation and maximizing the long-term value of the Company’s assets.  The revised 2016 capital program comprises drilling 25.9 net wells (18.5 in North Dakota, 1.5 in the Marcellus and 6.0 in the Canadian waterfloods) and bringing on-stream 24.2 net wells (13.6 in North Dakota, 4.6 in the Marcellus and 6.0 in the Canadian waterfloods).

Taking into account the reduced capital program, and the approximately 8,000 BOE per day of production divested since Enerplus released its original 2016 guidance, the revised production guidance for 2016 is 90,000 – 94,000 BOE per day. Expected crude oil and natural gas liquids production is modestly lower at 43,000 – 45,000 barrels per day, now representing 48% of total 2016 production at the midpoint (versus 44% previously).

Enerplus’ revised 2016 guidance is based on recent forward prices for crude oil and natural gas of US$38.63 per barrel WTI and US$2.43 per Mcf NYMEX respectively.  Under these assumptions, Enerplus anticipates an adjusted payout ratio of approximately 120% in 2016; however the Company expects to reduce debt levels during the year using the $193 million of proceeds from its Deep Basin divestments. Additionally, as a result of these divestments, Enerplus expects to record a gain of $145 million in the first quarter of 2016, thereby improving the Company’s debt to EBITDA ratio for 2016.  Enerplus’ debt covenants include a senior debt to EBITDA threshold of 3.5 times for a period of up to six months, after which it drops to 3.0 times. Under the price assumptions noted above, Enerplus does not expect to exceed its debt to EBITDA covenant in 2016. However, if the current commodity price levels persist, Enerplus would expect to begin negotiating covenant amendments with its lenders towards the end of 2016.

“The reduction to our dividend and reduced 2016 budget reflect our focus on maintaining our balance sheet strength and preserving the value of our high quality assets during this period of low commodity prices,” said Dundas. “We are committed to driving further improvement in our operational efficiencies and the sustainability of our business, and are well positioned to manage through this downturn.“

HEDGING UPDATE

Enerplus’ commodity hedging program will continue to help protect funds flow in 2016.  For the first quarter of 2016 we have hedged 17,000 barrels per day of crude oil which represents approximately 55% of our 2016 forecasted net oil production, after royalties. During the second quarter of 2016 we have hedged 11,000 barrels per day, which represents approximately 36% of our 2016 forecasted net oil production, after royalties.  For the third and fourth quarters of 2016 we have hedged 8,000 barrels per day which represents approximately 26% of our 2016 forecasted net oil production, after royalties. Protection levels are shown in the table below. Note that for the downside protection collars, when WTI prices settle below the sold put level in any given month, the collars provide protection at approximately US$14 per barrel above WTI index prices.

We have downside protection on approximately 62,500 Mcf per day of our natural gas production for 2016 consisting of a combination of NYMEX swaps and collars. This represents approximately 28% of our forecasted natural gas production after royalties. Note that for the downside protection collars, when NYMEX prices settle below the US$2.50 per Mcf sold put level in any given month, the collars provide protection at approximately US$0.50 per Mcf above NYMEX index prices.

OPERATIONAL REVIEW

North Dakota

North Dakota production averaged 29,600 BOE per day during the fourth quarter of 2015, an 18% increase in production relative to the fourth quarter of 2014. Enerplus spent $302 million in North Dakota in 2015, drilling 19.1 net wells with 23.3 net wells brought on-stream. The Company continues to deliver strong well results from its Fort Berthold position, where it is achieving among the best well performance and capital efficiencies in the basin.  The average initial 30-day production rate (“IP30”) of its operated on-stream wells in 2015 was over 1,700 BOE per day. Total well costs (drill, complete, tie-in and facilities) continue to trend down, having averaged US$9.4 million in the fourth quarter with current costs closer to US$9.0 million. At year-end 2015, Enerplus had approximately 9 drilled uncompleted (“DUC”) wells in North Dakota.

During 2016, the Company plans to reduce activity levels as a result of the continued low crude oil prices. Enerplus is running a single drilling rig and expects to complete fewer wells in 2016 relative to 2015, with capital spending expected to decline by approximately 60% from 2015 levels to $130 million. As a result, Enerplus’ DUC well inventory is expected to grow to an estimated 12 at year-end.

Marcellus

Marcellus production averaged 204 MMcf per day during the fourth quarter of 2015, up approximately 4% relative to the fourth quarter of 2014.  Strong well performance kept production relatively flat over the year despite low levels of spending and continued production curtailments.  Enerplus spent $32 million in the Marcellus in 2015 drilling 3.8 net wells with 7.2 net wells brought on-stream.  At year-end 2015, Enerplus had approximately 9 wells pending completion or tie-in.

Enerplus continues to plan for low levels of activity in the Marcellus during 2016, allocating approximately $20 million of capital to the play.

Marcellus basis differentials continued to be relatively wide during 2015 averaging US$1.37 per Mcf below NYMEX. Enerplus expects its realized Marcellus differentials to improve in 2016, partly as a result of securing 30,000 Mcf per day of Tennessee Gas Pipeline capacity that delivers to a market that prices closer to NYMEX, for US$0.63 per Mcf of firm demand tolls, effective August 1, 2016.  As well, the lower levels of industry spending in the region, combined with industry production curtailment at prevailing low NYMEX prices and the continued build out of regional takeaway capacity, are all expected to improve regional pricing.  Enerplus is guiding to a basis differential of US$1.00 per Mcf below NYMEX for our 2016 Marcellus production.  Despite the improving basis differential, Enerplus is still forecasting some production curtailment due to low NYMEX prices, particularly in the first half of the year.

Canadian Crude Oil

Production from the Canadian waterflood portfolio averaged 17,400 BOE per day during the fourth quarter of 2015, a decrease of 11% from the fourth quarter of 2014.  The decrease is largely a result of divesting the Pembina asset during the first quarter, along with some asset declines.  Capital spending in 2015 of $116 million was predominately directed to the Brooks drilling program and the Medicine Hat Glauc ‘C’ (“MHGC”) polymer project.

Enerplus expects to invest $50 million in its Canadian oil portfolio in 2016, which will be directed toward waterflood development and optimization activities.

INDEPENDENT RESERVES EVALUATION

All reserves information, including Enerplus’ U.S. reserves, has been prepared in accordance with Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) standards.  Independent reserves evaluations have been conducted on approximately 84% of the total proved plus probable net present value of future net revenue (before tax, discounted at 10%) of Enerplus’ reserves at December 31, 2015. McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluated 45% of Enerplus’ Canadian total proved plus probable net present value of future net revenue (before tax, discounted at 10%) and all of Enerplus’ U.S. oil assets. McDaniel also reviewed the internal evaluation completed by Enerplus on the remaining 55% of the total proved plus probable net present value of future net revenue (before tax, discounted at 10%) of Enerplus’ Canadian assets. Netherland, Sewell & Associates, Inc. (“NSAI”) evaluated all of Enerplus’ U.S. natural gas assets.

The following information sets out Enerplus’ gross reserves volumes at December 31, 2015 by product type and reserves category under McDaniel’s January 1, 2016 forecast price scenarios. Under different price scenarios, these reserves could vary as a change in price can affect the economic limit associated with a property. It should be noted that tables may not add due to rounding.

Subsequent to December 31, 2015, Enerplus entered into two separate agreements to divest of certain Canadian natural gas assets located in the Ansell area. Proved plus probable reserves associated with the two Ansell divestments are 93.4 BcfGE.

The following tables set forth the estimated gross and net reserves volumes and net present value of future net revenue attributable to the Company’s reserves at December 31, 2015, using forecast price and costs.

Reserves Summary

Reserves Reconciliation

The following tables outline the changes in Enerplus’ proved, probable and proved plus probable reserves, on a gross basis, from December 31, 2014 to December 31, 2015.

Due to changes in NI 51-101 product definitions effective July 1, 2015, 5,063 MMcf of proved reserves, 1,709 MMcf of probable reserves and 6,773 MMcf of proved plus probable reserves were moved from the December 31, 2014 Canadian Conventional Natural Gas opening volumes to the Shale Gas opening volumes.

In the U.S., 68,914 Mbbls of proved reserves, 52,631 Mbbls of probable reserves and 121,545 Mbbls of proved plus probable reserves were moved from the December 31, 2014 Light & Medium Oil opening volumes to the Tight Oil opening volumes.

Also in the U.S., 61,048 MMcf of proved reserves, 35,362 MMcf of probable reserves and 96,410 MMcf of proved plus probable reserves were moved from the December 31, 2014 Conventional Natural Gas opening volumes to the Shale Gas opening volumes.

Future Development Costs

Changes in forecast FDC occur annually as a result of development activities, acquisition and divestment activities and capital cost estimates that reflect the evaluators’ best estimate of the capital required to bring the proved and proved plus probable reserves on production. The aggregate of the exploration and development costs incurred in the most recent year and the change during the year in estimated future development costs generally reflect the total finding and development costs related to reserves additions for that year.

The following is a summary of the independent reserves evaluators’ estimated FDC required to bring the total proved and proved plus probable reserves on production: