ERF Enerplus Corporation

FORM 6‑K

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Report of Foreign Issuer pursuant to Rule 13‑a‑16 or 15d‑16

of the Securities Exchange Act of 1934

FOR THE MONTH OF MARCH, 2017

COMMISSION FILE NUMBER 1‑15150

The Dome Tower

Suite 3000, 333 – 7th Avenue S.W.

Calgary, Alberta

Canada T2P 2Z1

(403) 298‑2200

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20‑F or Form 40‑F.

Form 20‑F  ☐      Form 40‑F  ☒

Indicate by check mark if the registrant is submitting the Form 6‑K in paper as permitted by Regulation S‑T Rule 101(b)(1)

Yes ☐      No ☒

Indicate by check mark if the registrant is submitting the Form 6‑K in paper as permitted by Regulation S‑T Rule 101(b)(7)

Yes ☐      No ☒

Indicate by check mark whether, by furnishing the information contained in this Form, the registrant is also thereby furnishing the information to the Commission pursuant to Rule 12g3‑2(b) under the securities Exchange Act of 1934.

Yes ☐      No ☒

EXHIBIT INDEX

EXHIBIT 99.1 — Management’s Discussion and Analysis for the First Quarter ended March  31, 2017

EXHIBIT 99.2 — Unaudited Consolidated Financial Statements for the First Quarter ended March 31, 2017

EXHIBIT 99.3 — Certification of the Chief Executive Officer

EXHIBIT 99.4 — Certification of the Chief Financial Officer

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

DATE: May 5, 2017

Exhibit 99.1

MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)

The following discussion and analysis of financial results is dated May 5, 2017 and is to be read in conjunction with:

The following MD&A contains forward-looking information and statements. We refer you to the end of the MD&A under “Forward-Looking Information and Statements” for further information. The following MD&A also contains financial measures that do not have a standardized meaning as prescribed by accounting principles generally accepted in the United States of America (“U.S. GAAP”).  See “Non-GAAP Measures” at the end of the MD&A for further information.

BASIS OF PRESENTATION

The Interim Financial Statements and notes have been prepared in accordance with U.S. GAAP, including the prior period comparatives.  All amounts are stated in Canadian dollars unless otherwise specified and all note references relate to the notes included in the Interim Financial Statements. 

Where applicable, natural gas has been converted to barrels of oil equivalent (“BOE”) based on 6 Mcf:1 BOE and oil and natural gas liquids (“NGL”) have been converted to thousand cubic feet of gas equivalent (“Mcfe”) based on 0.167 bbl:1 Mcfe. BOE and Mcfe measures are based on an energy equivalent conversion method primarily applicable at the burner tip and do not represent a value equivalent at the wellhead.  Given that the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.  Use of BOE and Mcfe in isolation may be misleading. All production volumes are presented on a Company interest basis, being the Company’s working interest share before deduction of any royalties paid to others, plus the Company’s royalty interests unless otherwise stated. Company interest is not a term defined in Canadian National Instrument 51-101– Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and may not be comparable to information produced by other entities.

In accordance with U.S. GAAP, oil and gas sales are presented net of royalties in our Interim Financial Statements.  Under International Financial Reporting Standards, industry standard is to present oil and gas sales before deduction of royalties and as such this MD&A presents production, oil and gas sales, and BOE measures on this basis to remain comparable with our peers. 

OVERVIEW

Average daily production for the first quarter was 84,937 BOE/day, in line with our annual average production guidance range of 81,000 – 85,000 BOE/day. Production decreased 5% or 4,023 BOE/day from the fourth quarter of 2016 largely due to lower crude oil and liquids volumes following the December 30, 2016 sale of our non-operated North Dakota properties with production of approximately 5,000 BOE/day. The decrease in crude oil and liquids volume was offset by higher natural gas production from the Marcellus due to improved realized pricing. We are maintaining our annual average production guidance of 81,000 – 85,000 BOE/day, including approximately 38,500 – 41,500 bbls/day of crude oil and natural gas liquids. We continue to expect our average daily production and crude oil and liquids weighting to increase in the second half of the year as a result of significant capital spending in North Dakota, with expected fourth quarter average daily production of 86,000 – 91,000 BOE/day, including 43,000 – 48,000 bbls/day of crude oil and natural gas liquids.

Our capital spending for the first quarter was $120.4 million, in line with our expectation. Approximately 70% of spending directed to our North Dakota crude oil properties and 21% directed to our Canadian crude oil assets. We are maintaining our 2017 annual capital spending guidance of $450 million. 

Operating expenses for the first quarter came in below annual guidance of $7.25/BOE, totaling $50.3 million or $6.59/BOE. The decrease in operating costs was mainly due to additional savings related to our previously announced Canadian non-core asset divestments, as well as lower than expected activity levels. As a result, we are reducing our annual guidance for operating expenses to $6.85/BOE from $7.25/BOE. Cash G&A expenses for the first quarter were $14.3 million or $1.87/BOE compared to annual guidance of $1.85/BOE. We are maintaining our cash G&A guidance of $1.85/BOE.

Our commodity hedging program continued to provide funds flow protection, contributing cash gains of $6.6 million in the first quarter. Since the prior quarter, we have added to our commodity hedge positions. As of May 4, 2017, we have approximately 69% of our forecasted crude oil production, net of royalties, hedged in 2017, and approximately 46% and 15% of our crude oil production, net of royalties, hedged in 2018 and 2019, respectively, based on 2017 forecasted production.  We have also hedged approximately 25% of our forecasted natural gas production, net of royalties, in 2017. At March 31, 2017, the fair value of our crude oil and natural gas hedging contracts were in a net asset position of $12.7 million (December 31, 2016 - net liability of $38.3 million).

We recorded net income of $76.3 million and adjusted funds flow of $119.9 million in the first quarter, compared to $840.3 million and $107.7 million, respectively, in the fourth quarter of 2016. Both net income and adjusted funds flow benefited from improved pricing which offset the impact of reduced volumes, as well as an $8.8 million or 15% reduction in cash operating expenses.

At March 31, 2017, our total debt net of cash and restricted cash was $350.4 million and our net debt to adjusted funds flow ratio was 0.9x.

Subsequent to the first quarter, we closed the final portion of our previously announced Canadian divestment for proceeds of $60.8 million, after closing adjustments. Including the portion of the deal which closed in March 2017, the divested properties include the majority of our shallow gas assets as well as our Brooks waterflood property. These properties had combined production of approximately 7,300 BOE/day and accounted for $64.6 million of our future asset retirement obligation.  

RESULTS OF OPERATIONS

Production

Average daily production for the first quarter totaled 84,937 BOE/day, in line with our annual average guidance range of 81,000 – 85,000 BOE/day. Compared to production in the fourth quarter of 2016 of 88,960 BOE/day, production decreased by 5% or 4,023 BOE/day. Crude oil and liquids production decreased by 5,200 BOE/day primarily due to the December 30, 2016 sale of our non-operated North Dakota properties with production of approximately 5,000 BOE/day (90% crude oil and liquids). Natural gas production increased 2%  over the same period primarily due to higher production in the Marcellus as a result of improved realized prices. 

Production in the first quarter of 2017 decreased by 13% from production levels of 97,860 BOE/day during the same period of the prior year primarily due to the sale of non-core properties throughout 2016 with production of approximately 13,500 BOE/day. With the exception of the North Dakota non-operated sale, divested volumes related to Canadian non-core assets (86% natural gas). Production levels compared to the prior period were also impacted by reduced capital spending throughout 2016.

Our crude oil and natural gas liquids production weighting decreased to 43% in the first quarter of 2017 compared to 46% in the same period of 2016 primarily due to the North Dakota non-operated divestment.

Average daily production volumes for the three months ended March 31, 2017 and 2016 are outlined below:

We are maintaining our annual average production guidance of 81,000 – 85,000 BOE/day and our crude oil and natural gas liquids guidance of 38,500 – 41,500 bbls/day. This guidance includes the impact of our recently announced divestment of shallow gas assets and our Brooks waterflood property with production of approximately 7,300 BOE/day. We continue to expect our average daily production and crude oil and liquids weighting to increase in the second half of the year as a result of significant capital spending in North Dakota,  with fourth quarter average daily production expected to be between 86,000 – 91,000  BOE/day, including 43,000 – 48,000 bbls/day of crude oil and natural gas liquids. 

Pricing

The prices received for our crude oil and natural gas production directly impact our earnings, adjusted funds flow and financial condition. The following table compares quarterly average prices from the first quarter of 2017 to the previous four quarters:

(1)Excluding transportation costs, royalties and commodity derivative instruments.

CRUDE OIL AND NATURAL GAS LIQUIDS

Our average realized crude oil price during the quarter increased by 7% to $57.53/bbl, compared to a 5% increase in benchmark WTI prices. This increase was led mostly by stronger Bakken price differentials which improved by 18% during the quarter to average US$5.59/bbl below WTI. Bakken prices have continued to strengthen over the past year due to regional production declines, strong regional demand and the anticipated start-up of the Dakota Access Pipeline project in the second quarter of 2017. This project will result in regional pipeline capacity exceeding current production levels and should support stronger Bakken prices going forward. We continue to expect our Bakken crude oil differential to average US$4.50/bbl below WTI for all of 2017.

Our realized price differential for our Canadian crude oil production improved by 2% during the quarter compared to the previous quarter, due largely to our acquisition of a Canadian light crude oil waterflood property during November 2016.

Our realized price for natural gas liquids averaged $37.76/bbl during the quarter, an improvement of 77% compared to the fourth quarter of 2016, due to improvements in the underlying benchmark pricing as the supply-demand balance for natural gas liquids has improved.

NATURAL GAS

Our realized natural gas price during the first quarter improved by 26% compared to the fourth quarter of 2016 to average $3.63/Mcf. Benchmark NYMEX natural gas prices improved by 11% during the quarter, due to lower U.S. production and weather related demand increases in key regions of the U.S. through the latter part of the quarter.

Our realized Marcellus sales price differential excluding transportation and gathering improved by 32% during the quarter to average US$0.60/Mcf below NYMEX. Benchmark monthly Transco Leidy prices averaged US$0.63/Mcf below NYMEX during the first quarter. Continued growth in regional natural gas power plant demand and the steady addition of new pipeline projects in 2016 has resulted in demand exceeding supply in Northeast Pennsylvania. Our view remains that the Marcellus currently has excess pipeline capacity, and given the amount of additional infrastructure expected to be brought online over the next few

years, we expect Marcellus price differentials to continue to strengthen into 2018. We now expect our Marcellus natural gas realized price differential to average US$0.60/Mcf below NYMEX during 2017.

Most of our Canadian gas production is sold under multi-year fixed AECO basis differential contracts at prices better than those currently realized in the spot market. Our realized Canadian gas price differential averaged US$0.56/Mcf below NYMEX compared to the AECO benchmark monthly price that averaged US$1.10/Mcf below NYMEX in the first quarter.

FOREIGN EXCHANGE

The USD/CDN exchange rate was 1.33 USD/CDN at March 31, 2017, and averaged 1.32 USD/CDN during the first quarter of 2017 compared to 1.33 USD/CDN during the fourth quarter of 2016. The majority of our oil and natural gas sales are based on U.S. dollar denominated indices, and a weaker Canadian dollar relative to the U.S. dollar increases the amount of our realized sales. Because we report in Canadian dollars, the fluctuations in the Canadian dollar also impact our U.S. dollar denominated costs, capital spending and the reported value of our U.S. dollar denominated debt.

Price Risk Management

We have a price risk management program that considers our overall financial position and the economics of our capital expenditures.    

As of May 4, 2017, we have hedged approximately 18,680 bbls/day of our crude oil production for the remainder of 2017, which represents approximately 69% of our forecasted crude oil production, after royalties.  For 2018, we have hedged 12,500 bbls/day, which represents approximately 46% of our 2017 forecasted crude oil production, after royalties. For 2019, we have hedged 4,000 bbls/day, which represents approximately 15% of our 2017 forecasted crude oil production, after royalties. Our crude oil hedges are predominantly three way collars, which consist of a sold put, a purchased put and a sold call. When WTI prices settle below the sold put strike price over the contract term, the three way collars provide a limited amount of protection above the WTI settled price equal to the difference between the strike price of the purchased and sold puts. Overall, we expect our crude oil related hedging contracts to protect a significant portion of our adjusted funds flow.

As of May 4, 2017, we have hedged approximately 50,000 Mcf/day of our natural gas production for the remainder of 2017 using NYMEX three way collars. This represents approximately 25% of our forecasted natural gas production, after royalties. When NYMEX prices settle below the sold put strike price over the contract term, the three way collars provide a limited amount of protection above the NYMEX index prices equal to the difference between the strike price of the purchased and sold puts.

The following is a summary of our financial contracts in place at May 4, 2017, expressed as a percentage of our 2017 net production volumes:

ACCOUNTING FOR PRICE RISK MANAGEMENT

During the first quarter of 2017 we realized cash losses of $1.0 million on our crude oil contracts and cash gains of $7.6 million on our natural gas contracts. In comparison, during the first quarter of 2016 we realized cash gains of $36.6 million on our crude oil contracts and $3.0 million on our natural gas contracts. Cash gains recorded in the quarter on our natural gas contracts included a gain of $8.5 million on the unwind of a portion of our AECO-NYMEX basis physical contracts in conjunction with the sale of our Canadian non-core natural gas properties. Cash losses on crude oil contracts were primarily due to premiums paid on our three way collars.

As the forward markets for crude oil and natural gas fluctuate and new contracts are executed and existing contracts are realized, changes in fair value are reflected as either a non-cash charge or gain to earnings. At the end of the first quarter of 2017, the fair value of our crude oil contracts was in a net asset position of $15.5 million, while the fair value of our natural gas contracts was in a net liability position of $2.8 million. For the three months ended March 31, 2017, the change in the fair value of our crude oil and natural gas contracts represented gains of $44.4 million and $6.6 million, respectively.

Revenues

Oil and natural gas sales for the three months ended March 31, 2017 were $277.7 million, an increase of 63% from the same period in 2016. The increase in revenue during the first quarter was primarily a result of higher commodity pricing compared to the same period in 2016, which more than offset the impact of lower production.

Royalties and Production Taxes

Royalties are paid to government entities, land owners and mineral rights owners. Production taxes include state production taxes, Pennsylvania impact fees, freehold mineral taxes and Saskatchewan resource surcharges. A large percentage of our production is from U.S. properties where royalty rates are generally less sensitive to commodity price levels. During the three months ended March 31, 2017, royalties and production taxes increased to $60.3 million, from $35.2 million for the same period in 2016 primarily due to higher commodity prices.  Royalties and production taxes averaged 22% of oil and natural gas sales before transportation costs in the first quarter of 2017 compared to 21% for the same period in 2016 due to a greater portion of our production coming from our U.S. properties with higher overall royalty rates. Alberta’s Modernized Royalty Framework, which came into effect on January 1, 2017, has not had a significant impact on our Canadian royalties.

We are maintaining our average royalty and production tax rate guidance of 24% in 2017. We continue to expect our royalty rate to increase in the latter half of the year as a result of a higher U.S. production weighting.

Operating Expenses

(1)Non-cash (gains)/losses on fixed price electricity swaps.

Operating expenses for the first quarter of 2017 totaled $50.4 million or $6.59/BOE, below our annual  guidance of $7.25/BOE. Operating costs decreased by 31% from $72.6 million or $8.15/BOE during the same period of the prior year due to the divestment of higher operating cost Canadian properties throughout 2016, along with lower repairs and maintenance, fluid handling and gas facility charges compared to the prior period.

During the first quarter of 2017, we realized additional savings from our previously announced non-core divestments and cost reductions due to lower than expected activity levels. As a result, we are lowering our 2017 guidance for operating expenses to $6.85/BOE from $7.25/BOE. Although our operating costs were below guidance during the first quarter, we expect costs to increase on a per BOE basis during the second half of the year with our higher liquids weighting and scheduled turnarounds in Canada. 

Transportation Costs

For the three months ended March 31, 2017, transportation costs were $29.6 million or $3.88/BOE,  below our annual guidance of $4.00/BOE. Transportation costs have increased by $3.9 million from $25.7 million or $2.89/BOE during the same period in 2016.  The increase in the cost per BOE is primarily due to additional firm transportation commitments, including 30,000 Mcf/day of additional interstate pipeline capacity from the Marcellus region to downstream connections that came into effect in August 2016. 

We are maintaining our 2017 guidance for transportation costs of $4.00/BOE, as our growing U.S. production volumes have higher associated transportation costs.

Netbacks

The crude oil and natural gas classifications below contain properties according to their dominant production category. These properties may include associated crude oil, natural gas or natural gas liquids volumes which have been converted to the equivalent BOE/day or Mcfe/day and as such, the revenue per BOE or per Mcfe may not correspond with the average selling price under the “Pricing” section of this MD&A.

(1)See “Non-GAAP Measures” in this MD&A.

Crude oil and natural gas netbacks per BOE after hedging were higher for the three months ended March 31, 2017 compared to the same period in 2016 primarily due to significantly higher oil and natural gas sales as a result of improvements in commodity prices and differentials in North Dakota and Marcellus regions, along with reductions to our operating expenses. In 2017, our crude oil properties accounted for 63% of our netback before hedging compared to 100% of our netback during the first quarter of 2016.

General and Administrative (“G&A”) Expenses

Total G&A expenses include cash G&A expenses and share-based compensation (“SBC”) charges related to our long-term incentive plans (“LTI plans”). See Note 10 and Note 13 to the Interim Financial Statements for further details.

For the three months ended March 31, 2017, cash G&A expenses were $14.3 million or $1.87/BOE, in line with our annual guidance of $1.85/BOE. The decrease in cash G&A expenses from $18.4 million or $2.07/BOE in the same period in 2016 was primarily due to continued cost savings initiatives and the impact of reductions in staff levels throughout 2016 as we continue to divest of non-core properties and focus our business.

During the quarter, we reported cash SBC expense of $0.2 million or $0.02/BOE, a decrease of 71% compared to $0.7 million or $0.08/BOE during the same period in 2016. During the first quarter of 2016, we recorded expenses related to our Director Share Unit (“DSU”) plan and the final settlement of our cash-settled Restricted Share Unit (“RSU”) plan, while the current quarter expense relates solely to the annual grant of our DSU plan offset by the impact of a lower share price on outstanding units. Our DSU plan is the only remaining LTI plan that we intend to settle in cash. We recorded non-cash SBC of $8.1 million or $1.06/BOE in the first quarter of 2017 compared to $3.4 million or $0.39/BOE during the same period in 2016. The increase in non-cash SBC was a result of an improvement in our performance multiplier based on our relative return in the Toronto Stock Exchange Oil and Gas Producers Index.

We have hedges in place on the outstanding cash-settled grants under our LTI plans. In the first quarter we recorded a non-cash mark-to-market loss of $0.9 million on these hedges. As of March 31, 2017 we had 470,000 units hedged at a weighted average price of $16.89 per share.

We are maintaining our cash G&A guidance of $1.85/BOE. 

Interest Expense

For the three months ended March 31, 2017, we recorded total interest expense of $10.1 million, compared to $14.5 million for the same period in 2016. The decrease in interest expense corresponds to a decrease in the aggregate principal amount of our outstanding senior notes following our repurchase of US$267 million of senior notes during the first half of 2016, along with a decrease in our drawn bank credit facility compared to the same period in 2016.  

At March 31, 2017, we were essentially undrawn on our $800 million bank credit facility, and our debt balance consisted primarily of fixed interest rate senior notes with a weighted average interest rate of 5.0%. See Note 7 in the Interim Financial Statements for further details.

Foreign Exchange

For the three months ended March 31, 2017, we recorded a net foreign exchange gain of $3.8 million, compared to a gain of $54.4 million for the same period in 2016. Realized gains and losses relate primarily to day-to-day transactions recorded in foreign currencies, while unrealized gains and losses are recorded on the translation of our U.S. dollar denominated debt and working capital at each period end. Comparing March 31, 2017  to December 31, 2016, the Canadian dollar strengthened relative to the U.S. dollar resulting in unrealized gains of $3.9 million. See Note 11 to the Interim Financial Statements for further details.

Capital Investment

Capital spending for the three months ended March 31, 2017, totaled $120.4 million, compared to $43.3 million for the same period in 2016. The increase is in line with our strategy to re-initiate growth through an increased capital program in 2017. During the first quarter we spent $85.1 million on our North Dakota crude oil properties, $25.1 million on our Canadian crude oil properties and $9.8 million on our Marcellus natural gas assets.

During the first quarter, we completed a portion of our previously announced Canadian asset divestments. Although we recorded nominal proceeds on the divestment, which had associated natural gas production of 1,700 BOE/day, it resulted in a $25.1 million decrease in our asset retirement obligation. This divestment was offset by adjustments pertaining to prior period divestments. In comparison, during the same period of 2016 we disposed of several properties including certain Canadian Deep Basin properties located in Alberta for proceeds of $187.8 million with production of 5,400 BOE/day.

Subsequent to the first quarter, we closed the remaining 5,600 BOE/day of our previously announced divestments of various non-core Canadian properties. This included the remainder of our shallow gas assets and our Brooks waterflood property, for aggregate proceeds of $60.8 million, after closing adjustments.  

We continue to expect 2017 annual capital spending of $450 million.

Gain on Asset Sales and Note Repurchases

Under full cost accounting rules, divestments of oil and natural gas properties are generally accounted for as adjustments to the full cost pool with no recognition of a gain or loss. However, if not recognizing a gain or loss on the transaction would significantly alter the relationship between a cost centre’s capitalized costs and proved reserves, then a gain or loss must be recognized.  Gains and losses are evaluated on a case by case basis for each asset sale, and future sales may or may not result in such treatment. We did not record any gains or losses on divestments completed during the first quarter of 2017. In comparison, we recorded a gain of $145.1 million on asset divestments during the first quarter of 2016. 

During the comparative period ended March 31, 2016, we recorded a gain of $7.1 million on the repurchase of US$172 million in outstanding senior notes at a discount to par value.

Depletion, Depreciation and Accretion (“DD&A”)

DD&A of property, plant and equipment (“PP&E”) is recognized using the unit-of-production method based on proved reserves. For the three months ended March 31, 2017, DD&A decreased when compared to the same period of 2016 primarily due to the cumulative effects of asset impairments recorded during 2016 as well as lower overall production.

Impairment

Under U.S. GAAP, the full cost ceiling test is performed on a country-by-country basis using estimated after-tax future net cash flows discounted at 10 percent from proved reserves using SEC constant prices ("Standardized Measure"). SEC prices are calculated as the unweighted average of the trailing twelve first-day-of-the-month commodity prices. The Standardized Measure is not related to Enerplus' investment criteria and is not a fair value based measurement, but rather a prescribed accounting calculation. Under U.S. GAAP, impairments are not reversed in future periods.

The trailing twelve month average crude oil and natural gas prices increased in the first quarter of 2017 compared to a decrease during the same period in 2016. There were no non-cash impairments recorded in the three months ended March 31, 2017, compared to $46.2 million in the same period of 2016. 

Many factors influence the allowed ceiling value versus our net capitalized cost base, making it difficult to predict with reasonable certainty the value of impairment losses from future ceiling tests. The primary factors include future first-day-of-the-month commodity prices, reserves revisions, our capital expenditure levels and timing, acquisition and divestment activity, as well as production levels, which affect DD&A expense. Although the trailing twelve month average commodity prices are approximately in line with current levels, there is the potential for prices to decline, impacting the ceiling value and resulting in non-cash impairments. See Note 5 to the Interim Financial Statements for trailing twelve month prices.

Asset Retirement Obligation

In connection with our operations we incur abandonment and reclamation costs related to assets such as surface leases, wells, facilities and pipelines. Total asset retirement obligations included on our balance sheet are based on our net ownership interest and management’s estimate of costs to abandon and reclaim such assets and the timing of the cost to be incurred in future periods. We have estimated the net present value of our asset retirement obligation to be $155.5 million at March 31, 2017, compared to $181.7 million at December 31, 2016. Asset retirement obligation settlements were $2.5 million during the first quarters of 2017 and 2016. As a result of our divestments in the first quarter of 2017, we have reduced our asset retirement obligation by $25.1 million or 14%.  

Income Taxes

We recorded a total tax expense of $28.9 million during the first quarter of 2017 compared to $256.3 million for the same period in 2016. The current quarter tax expense is primarily based on income reported in Canada and the U.S. compared to the first quarter of 2016 where we recorded an additional valuation allowance. We assess the recoverability of our deferred income tax assets each period to determine whether it is more likely than not all or a portion of our deferred income tax assets will be realized. This assessment is primarily the result of projecting future taxable income using benchmark forward prices for 2017, held constant and adjusted for other significant items affecting taxable income. Our overall net deferred income tax asset was $700.2 million at March 31, 2017 (December 31, 2016 - $733.4 million).

LIQUIDITY AND CAPITAL RESOURCES

There are numerous factors that influence how we assess our liquidity and leverage, including commodity price cycles, capital spending levels, acquisition and divestment plans, hedging and dividend levels. We also assess our leverage relative to our most restrictive debt covenant under our bank credit facility and senior notes, which is a maximum senior debt to earnings before interest, taxes, depreciation, amortization, impairment and other non-cash charges (“adjusted EBITDA”) ratio of 3.5x for a period of up to six months, after which it drops to 3.0x. At March 31, 2017, our senior debt to adjusted EBITDA ratio was 0.9x and our net debt to adjusted funds flow ratio was 0.9x. Although it is not included in our debt covenants, the net debt to adjusted funds flow ratio is often used by investors and analysts to evaluate our liquidity.

Total debt net of cash and restricted cash at March 31, 2017 was $350.4 million, a decrease of 7% compared to $375.5 million at December 31, 2016. Total debt was comprised of $4.0 million of bank indebtedness and $740.0 million of senior notes less $393.6 million in cash, including restricted cash.  Proceeds from the December, 2016 sale of our non-operated North Dakota properties are being held in escrow for a period of up to 180 days from the date of closing to facilitate possible future like-kind transactions in accordance with U.S. federal tax regulations. These proceeds have been classified as restricted cash on our balance sheet. At March 31, 2017, we were essentially undrawn on our $800 million bank credit facility.

Our adjusted payout ratio, which is calculated as cash dividends plus capital and office expenditures divided by adjusted funds flow, was 107% for the three months ended March 31, 2017, compared to 138% for the same period in 2016.

Our working capital deficiency, excluding cash, restricted cash and current deferred financial assets and liabilities, increased to $130.7 million at March 31, 2017 from $94.4 million at December 31, 2016. We expect to finance our working capital deficit and our ongoing working capital requirements through cash, adjusted funds flow and our bank credit facility. We have sufficient liquidity to meet our financial commitments, as disclosed under “Commitments” in the Annual MD&A.

At March 31, 2017, we were in compliance with all covenants under our bank credit facility and outstanding senior notes.  Our bank credit facility and senior note purchase agreements have been filed as material documents on our SEDAR profile at www.sedar.com.  

The following table lists our financial covenants as at March 31, 2017:

Definitions

“Senior debt” is calculated as the sum of drawn amounts on our bank credit facility, outstanding letters of credit and the principal amount of senior notes.

“Adjusted EBITDA” is calculated as net income less interest, taxes, depletion, depreciation, amortization, impairment and other non-cash gains and losses. Adjusted EBITDA is calculated on a trailing twelve-month basis and is adjusted for material acquisitions and divestments. Adjusted EBITDA for the three months and the trailing twelve months ended March 31, 2017 were $130.1 million and $845.2 million, respectively.

“Total debt” is calculated as the sum of senior debt plus subordinated debt. Enerplus currently does not have any subordinated debt.

“Capitalization” is calculated as the sum of total debt and shareholder’s equity plus a $1.1 billion adjustment related to our adoption of U.S. GAAP.

Footnotes

(1)See “Non-GAAP Measures” in this MD&A for a reconciliation of adjusted EBITDA to net income.

(2)Senior debt to adjusted EBITDA may increase to 3.5x for a period of 6 months for the senior notes, after which the ratio decreases to 3.0x.

(3)Senior debt to consolidated present value of total proved reserves is calculated annually on December 31 based on before tax reserves at forecast prices discounted at 10%.

Dividends

During the three months ended March 31, 2017, we reported total dividends of $7.2 million or $0.03 per share, compared to $14.5 million or $0.07 per share for the same period in 2016. Effective with our April 2016 payment, we reduced our monthly dividend from $0.03 per share to $0.01 per share to provide additional financial flexibility and balance adjusted funds flow with capital and dividends.

The dividend is part of our strategy to create shareholder value; however, a sustained low price environment may impact our ability to pay dividends. We continue to monitor commodity prices and economic conditions and are prepared to make adjustments as necessary.

Shareholders’ Capital

During the first quarter of 2017, a total of 1,646,000 shares were issued pursuant to our LTI plans and accordingly, $21.0 million was transferred from paid-in capital to share capital (2016 – 594,000; $9.4 million). For further details, see Note 13 to the Interim Financial Statements.

On March 28, 2017, we filed a short form base shelf prospectus (the “Shelf Prospectus”) with securities regulatory authorities in each of the provinces of Canada and a Registration Statement with the U.S. Securities Exchange Commission. The Shelf Prospectus allows us to offer and issue up to an aggregate amount of $2.0 billion of common shares, preferred shares, warrants, subscription receipts and units by way of one or more prospectus supplements during the 25-month period that the Shelf Prospectus remains in place.  

At May 4, 2017, we had 242,128,944 shares outstanding.

SELECTED CANADIAN AND U.S. FINANCIAL RESULTS