Enerplus Announces Strong First Quarter 2016 Results
All financial information contained within this news release has been prepared in accordance with U.S. GAAP, except as noted under "Non-GAAP Measures". This news release includes forward-looking statements and information within the meaning of applicable securities laws. Readers are advised to review the "Forward-Looking Information and Statements" at the conclusion of this news release. A full copy of Enerplus' First Quarter 2016 Financial Statements and MD&A are available on the Company's website at www.enerplus.com, under its SEDAR profile at www.sedar.com and on the EDGAR website at www.sec.gov.
CALGARY, May 6, 2016 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce its results from operations for the first quarter of 2016.
"We continue to position our company to deliver long-term profitability in a lower commodity price environment. Our focus on reducing costs and driving efficiencies across the organization has resulted in a meaningful reduction to our cost structure. As a result, we are reducing our combined operating, transportation and G&A cost guidance by $1.30 per BOE in 2016," stated Ian C. Dundas, President & CEO. "In addition, we have been delivering on our portfolio optimization objectives with non-core divestments generating net proceeds of $188 million in the first quarter, further strengthening our company's balance sheet. Operationally, our assets continue to deliver strong results and we remain on track to achieve our targets."
KEY TAKEAWAYS:
- Production averaged 97,860 BOE per day during the quarter, including approximately 45,000 barrels per day of crude oil and natural gas liquids. Total production was down 8% from the previous quarter primarily as a result of non-core divestment activity during the fourth quarter of 2015 and first quarter of 2016, in which we divested properties with associated production of approximately 9,100 BOE per day. The divested production was approximately 90% natural gas weighted and, as a result, our crude oil and natural gas liquids weighting increased to 46% in the first quarter, from 43% in the previous quarter.
- We continued to see outperformance from our North Dakota wells along with strong production results from our Canadian oil portfolio during the quarter. As a result, and despite the previously announced second quarter divestment of 2,300 BOE per day, we are maintaining our 2016 production guidance range of 90,000 to 94,000 BOE per day and 43,000 to 45,000 barrels per day of crude oil and natural gas liquids.
- First quarter funds flow was $41.7 million ($0.20 per share), down approximately 60% from the fourth quarter of 2015 as a result of significantly lower crude oil and natural gas prices and lower realized gains on crude oil and natural gas hedging contracts.
- We recorded a net loss of $173.7 million ($0.84 per share) in the first quarter. Our first quarter earnings benefited from a combined gain of $152.2 million on property divestments and the repurchase of a portion of our outstanding senior notes. These gains were offset by non-cash charges of $304.7 million related to asset impairment and a valuation allowance taken on our deferred tax asset as a result of the decline in 12-month trailing average commodity prices.
- Our focus on maintaining our balance sheet strength and preserving the value of our high quality inventory during this period of low commodity prices resulted in a 50% reduction in capital spending from the fourth quarter of 2015, to $43.3 million. Capital spending was focused on our crude oil properties with $19.8 million directed to North Dakota and $19.1 million directed to our Canadian oil portfolio. We continue to budget 2016 capital spending of $200 million, with approximately 90% allocated to our crude oil plays (65% North Dakota, 25% Canada).
- Our ongoing cost reduction efforts are delivering strong results. First quarter operating expenses of $8.15 per BOE were 6% lower than the fourth quarter of 2015 and 16% lower than the first quarter of 2015, despite lower volumes. Based on cost savings to date, the strengthening Canadian dollar relative to our U.S. dollar denominated operating costs, and the previously announced divestment of our higher cost northwest Alberta assets, we are reducing our 2016 guidance for operating expenses to $8.50 per BOE from $9.50 per BOE. We are also reducing our transportation cost guidance to $3.10 per BOE from $3.30 per BOE as a result of the strengthening Canadian dollar.
- Cash G&A expenses during the first quarter were $2.07 per BOE, down 12% from the same period in 2015 and up 18% from the fourth quarter of 2015 largely due to severance payments incurred in the first quarter. As a result of the reduction of our workforce to better align with our more focused asset base and improved organizational efficiencies, we are reducing our 2016 guidance for cash G&A expenses to $2.00 per BOE from $2.10 per BOE.
- Overall, taking into account our reduced operating, transportation and G&A expense guidance, we expect our 2016 cash costs to be approximately $1.30 per BOE lower than previously forecast.
- As previously announced, effective with the April 2016 payment, we reduced the monthly dividend from $0.03 per share to $0.01 per share. This reduction reflected the need to rebalance the dividend level to better align with reduced funds flow in the context of the sustained low commodity price environment.
- We further strengthened our balance sheet during the first quarter, ending the period with total debt, net of cash, of $992.8 million compared to $1,216.2 million at December 31, 2015. The $223 million reduction in total debt was a result of applying divestment proceeds against outstanding debt combined with the strengthening Canadian dollar relative to our U.S. dollar denominated senior notes. Total debt was comprised of $844.5 million of senior notes and $149.6 million of bank indebtedness (19% drawn on our $800 million facility) less $1.3 million in cash. At March 31, 2016, our senior debt to EBITDA ratio was 1.6 times and our debt to funds flow ratio was 2.3 times.
- We had continued success in divesting non-core assets during the quarter which provided net proceeds of approximately $188 million. These proceeds, along with our largely undrawn bank credit facility, were used to fund the repurchase of US$172 million of our senior notes during the quarter, and a total of US$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, resulting in a total gain of $19 million. As a result of replacing fixed term, higher interest rate senior debt with lower interest rate bank debt and using divestment proceeds to repay outstanding debt, we expect to save approximately US$13 million in interest expense on an annualized basis. Utilizing a portion of our bank credit facility in place of the senior notes provides additional flexibility within our capital structure to reduce our leverage further as cash becomes available.
- Subsequent to the quarter, we announced an additional non-core divestment of certain assets located in northwest Alberta for proceeds of $95.5 million, subject to closing adjustments. Expected annual average 2016 production associated with these assets is approximately 2,300 BOE per day (50% natural gas). This divestment is expected to close in the second quarter of 2016 and we expect to realize a gain of approximately $70 million as a result of the sale. Upon closing, this will bring total 2016 divestment proceeds to $283 million.
- In connection with our non-core assets sales, we have materially reduced the Company's future abandonment liabilities. Since the start of 2015, we have reduced our asset retirement obligations by over 30%.
ASSET ACTIVITY
North Dakota
North Dakota production averaged 29,200 BOE per day during the first quarter, largely flat from the previous quarter and up 36% from the same period in 2015. We spent $19.8 million in North Dakota in the quarter drilling 4.4 net wells and bringing 2.5 net wells on-stream. Our well performance continues to be strong, with the two operated on-stream wells in the quarter delivering initial 30-day production rates of 1,990 and 1,750 BOE per day. Subsequent to the quarter, two further wells were brought on-stream that have averaged in excess of 2,000 BOE per day in the first 30 days of production. Well costs continue to trend down due to reduced drilling days, completions optimization and changes to facilities design. Our total drilling, completion, tie-in and facilities costs are currently US$8.5 million, down approximately 35% from 2014 levels.
We continue to run a single drilling rig in North Dakota given the sustained low commodity price environment but retain the flexibility to increase activity quickly given our inventory of drilled uncompleted wells, which stood at approximately 11 at the end of the first quarter. Our 2016 capital program is primarily focused in North Dakota, where we expect to spend approximately $130 million during the full year 2016, keeping North Dakota production largely flat.
Canada
Total production from Canada averaged 32,590 BOE per day during the quarter. Activity was focused on our waterflood assets at Cadogan, Giltedge and southeast Saskatchewan, where we drilled 4 producers and 3 injector wells. Results from the program have exceeded expectations with the wells producing at, or above, our type curve forecast. Production from the waterflood assets averaged 17,500 BOE per day during the quarter. Activity in Canada during the rest of 2016 will be largely focused on performance and cost optimization work.
Marcellus
Marcellus production averaged 190 MMcf per day during the first quarter, down approximately 7% from the previous quarter due to continued low levels of activity as a result of weak regional natural gas pricing. Capital spending in the quarter was $3.5 million, with 1.3 net wells brought on-stream. We continue to plan for modest levels of activity in the Marcellus, forecasting full year 2016 spending of $20 million, a reduction of approximately 37% from 2015 spending.
Production and Capital Spending(1)
| Three months ended March 31, 2016 |
||
| Crude Oil & NGLs (bbls/day) |
Average Production |
Capital Spending |
| Canada |
15,990 |
$19.1 |
| United States |
29,012 |
$20.7 |
| Total Crude Oil & NGLs (bbls/day) |
45,002 |
$39.8 |
| Natural Gas (Mcf/day) |
||
| Canada |
99,539 |
- |
| United States |
217,611 |
$3.5 |
| Total Natural Gas (Mcf/day) |
317,150 |
$3.5 |
| Company Total (BOE/day) |
97,860 |
$43.3 |
| (1) Table may not add due to rounding |
||
| NET DRILLING ACTIVITY(1)– for the three months ended March 31, 2016 |
||
| Crude Oil |
Wells Drilled |
Wells On-stream |
| Canada |
7.0 |
6.0 |
| United States |
4.4 |
2.5 |
| Total Crude Oil |
11.4 |
8.5 |
| Natural Gas |
||
| Canada |
- |
- |
| United States |
0.1 |
1.3 |
| Total Natural Gas |
0.1 |
1.3 |
| Company Total |
11.5 |
9.8 |
| (1) Table may not add due to rounding |
||
CRUDE OIL & NATURAL GAS PRICING
The WTI benchmark crude oil price fell by 21% versus the previous quarter as seasonal refinery outages combined with continued oversupply drove U.S. oil inventories to near-maximum levels. This supply imbalance pushed WTI prices to a low of US$26.05 per barrel in February before improving by the end of the quarter as refinery demand returned and there were growing indications of supply declines in North America and elsewhere. Modestly weaker crude oil differentials in both Canada and the U.S. also contributed to the weakness in realized oil prices during the quarter. Our average Bakken realized crude oil price differential was US$8.38 per barrel below WTI in the quarter.
NYMEX natural gas prices fell by 8% and AECO monthly prices fell by approximately 20% compared to the previous quarter. Both markets remained weak in response to continued high production with lower than normal seasonal demand that resulted in significant storage surpluses across North America relative to the first quarter of 2015.
Our overall realized natural gas price outperformed changes in NYMEX and AECO prices due to improving differentials in the Marcellus. Weaker NYMEX prices narrowed Marcellus benchmark differentials, resulting in an average Marcellus realized price differential of US$0.91 per Mcf below NYMEX, a 19% improvement from the previous quarter. We continue to expect our realized Marcellus differentials in 2016 to improve relative to recent years due to reduced industry spend and the continued build out of regional take-away capacity.
RISK MANAGEMENT
We continue to protect a portion of our funds flow through commodity hedging and have added additional price protection on both our crude oil and natural gas production in 2017. Currently, we have a combination of swaps and collars in 2016 and 2017 covering approximately 31% and 20% respectively, of forecast net oil production, after royalties. For natural gas, we have a combination of swaps and collars in 2016 and 2017 covering approximately 31% and 16% respectively, of forecast net natural gas production, after royalties.
Commodity Hedging Detail (as at May 2, 2016)
| Crude Oil |
NYMEX Natural |
|||||
| Apr 1, 2016 – |
Jul 1, 2016 – |
Jan 1, 2017 – |
Apr 1, 2016 – |
Nov 1, 2016 – |
Jan 1, 2017 – |
|
| Swaps |
||||||
| Sold Swaps |
$64.28 |
- |
- |
$2.53 |
$2.48 |
- |
| Volume (bbl/d or Mcf/d) |
3,000 |
- |
- |
50,000 |
25,000 |
- |
| % of net production |
10% |
- |
- |
23% |
11% |
- |
| 3 Way Collars |
||||||
| Sold Puts |
$50.13 |
$49.78 |
$35.67 |
$2.50 |
$2.50 |
$2.00 |
| Volume (bbl/d or Mcf/d) |
8,000 |
8,000 |
6,000 |
25,000 |
25,000 |
35,000 |
| % of net production |
26% |
26% |
20% |
11% |
11% |
16% |
| Purchased Puts |
$64.38 |
$63.98 |
$48.18 |
$3.00 |
$3.00 |
$2.67 |
| Volume (bbl/d or Mcf/d) |
8,000 |
8,000 |
6,000 |
25,000 |
25,000 |
35,000 |
| % of net production |
26% |
26% |
20% |
11% |
11% |
16% |
| Sold Calls |
$79.38 |
$79.63 |
$60.00 |
$3.75 |
$3.75 |
$3.32 |
| Volume (bbl/d or Mcf/d) |
8,000 |
8,000 |
6,000 |
25,000 |
25,000 |
35,000 |
| % of net production |
26% |
26% |
20% |
11% |
11% |
16% |
| Collars |
||||||
| Purchased Puts |
$33.41 |
- |
- |
- |
- |
- |
| Volume (bbl/d or Mcf/d) |
1,670 |
- |
- |
- |
- |
- |
| % of net production |
5% |
- |
- |
- |
- |
- |
| Sold Puts |
$41.75 |
- |
- |
- |
- |
- |
| Volume (bbl/d or Mcf/d) |
1,670 |
- |
- |
- |
- |
- |
| % of net production |
5% |
- |
- |
- |
- |
- |
| (1) Based on weighted average price (before premiums), assuming average annual production of 92,000 BOE/day for 2016 and 2017, less royalties |
||||||
2016 REVISED GUIDANCE
We have revised our full year 2016 guidance as a result of further reductions to our cost structure related to operating, transportation and G&A expenses. Capital spending and production guidance remain unchanged. The revised guidance considers the announced divestment of our northwest Alberta assets expected to close during the second quarter.
| Summary of 2016 Expectations |
Revised Guidance |
Original Guidance |
| Capital spending |
$200 million |
$200 million |
| Average annual production |
90,000 – 94,000 BOE/day |
90,000 – 94,000 BOE/day |
| Crude oil and natural gas liquids volumes |
43,000 – 45,000 BOE/day |
43,000 – 45,000 BOE/day |
| Average royalty and production tax rate |
23% |
23% |
| Operating expenses |
$8.50/BOE |
$9.50/BOE |
| Transportation expense |
$3.10/BOE |
$3.30/BOE |
| Cash G&A expenses |
$2.00/BOE |
$2.10/BOE |
Q1 2016 CONFERENCE CALL DETAILS
A conference call hosted by Ian C. Dundas, President and CEO will be held at 8:00AM MT (10:00AM ET) today to discuss these results. Details of the conference call are as follows:
| Date: |
Friday, May 6, 2016 |
| Time: |
8:00 AM MT (10:00 AM ET) |
| Dial-In: |
647-427-7450 |
| 888-231-8191 (toll free) |
|
| Audiocast: |
http://event.on24.com/r.htm?e=1169442&s=1&k=DB13444A94245E531DE0286BB7C8AC04 |
To ensure timely participation in the conference call, callers are encouraged to dial in 15 minutes prior to the start time to register for the event. A telephone replay will be available for 30 days following the conference call and can be accessed at the following numbers:
| Dial-In: |
416-849-0833 |
| 1-855-859-2056 (toll free) |
|
| Passcode: |
86983471 |
SELECTED FINANCIAL RESULTS
| Three months ended March 31, |
||||
| 2016 |
2015 |
|||
| Financial (000's) |
||||
| Funds Flow(4) |
$ |
41,727 |
$ |
109,164 |
| Dividends to Shareholders |
14,464 |
47,359 |
||
| Net Income/(Loss) |
(173,666) |
(293,206) |
||
| Debt Outstanding - net of cash |
992,837 |
1,272,204 |
||
| Capital Spending |
43,276 |
167,011 |
||
| Property and Land Acquisitions |
3,554 |
(236) |
||
| Property Divestments |
187,768 |
3,712 |
||
| Debt to Funds Flow Ratio(4) |
2.3x |
1.7x |
||
| Financial per Weighted Average Shares Outstanding |
||||
| Funds Flow |
$ |
0.20 |
$ |
0.53 |
| Net Income/(Loss) |
(0.84) |
(1.42) |
||
| Weighted Average Number of Shares Outstanding (000's) |
206,716 |
205,845 |
||
| Selected Financial Results per BOE(1)(2) |
||||
| Oil & Natural Gas Sales(3) |
$ |
19.14 |
$ |
26.89 |
| Royalties and Production Taxes |
(3.95) |
(5.50) |
||
| Commodity Derivative Instruments |
4.45 |
9.56 |
||
| Cash Operating Expenses |
(8.12) |
(9.56) |
||
| Transportation Costs |
(2.89) |
(2.92) |
||
| General and Administrative Expenses |
(2.07) |
(2.36) |
||
| Cash Share-Based Compensation |
(0.08) |
(0.80) |
||
| Interest, Foreign Exchange and Other Expenses |
(1.81) |
(3.28) |
||
| Current Income Tax Recovery |
0.02 |
- |
||
| Funds Flow |
$ |
4.69 |
$ |
12.03 |
SELECTED OPERATING RESULTS
| Three months ended March 31, |
||||
| 2016 |
2015 |
|||
| Average Daily Production(2) |
||||
| Crude Oil (bbls/day) |
39,508 |
39,355 |
||
| Natural Gas Liquids (bbls/day) |
5,494 |
3,735 |
||
| Natural Gas (Mcf/day) |
317,150 |
346,589 |
||
| Total (BOE/day) |
97,860 |
100,855 |
||
| % Crude Oil & Natural Gas Liquids |
46% |
43% |
||
| Average Selling Price (2)(3) |
||||
| Crude Oil (per bbl) |
$ |
31.59 |
$ |
44.04 |
| Natural Gas Liquids (per bbl) |
11.34 |
22.48 |
||
| Natural Gas (per Mcf) |
1.77 |
2.58 |
||
| Net Wells drilled |
11 |
28 |
||
| (1) |
Non-cash amounts have been excluded. |
| (2) |
Based on Company interest production volumes. See "Basis of Presentation" section in the First Quarter 2016 MD&A. |
| (3) |
Before transportation costs, royalties and commodity derivative instruments. |
| (4) |
These non-GAAP measures may not be directly comparable to similar measures presented by other entities. See "Non-GAAP Measures" section in the First Quarter 2016 MD&A. |
| Three months ended March 31, |
||||||
| Average Benchmark Pricing |
2016 |
2015 |
||||
| WTI crude oil (US$/bbl) |
$ |
33.45 |
$ |
48.64 |
||
| AECO natural gas – monthly index (CDN$/Mcf) |
2.11 |
2.95 |
||||
| AECO natural gas – daily index (CDN$/Mcf) |
1.83 |
2.75 |
||||
| NYMEX natural gas – last day (US$/Mcf) |
2.09 |
2.98 |
||||
| USD/CDN exchange rate |
1.37 |
1.24 |
||||
Share Trading Summary |
CDN* ERF |
U.S.** - ERF |
||||
| For the three months ended March 31, 2016 |
(CDN$) |
(US$) |
||||
| High |
$ |
5.37 |
$ |
4.03 |
||
| Low |
$ |
2.68 |
$ |
1.84 |
||
| Close |
$ |
5.09 |
$ |
3.93 |
||
| * TSX and other Canadian trading data combined. |
||||||
| ** NYSE and other U.S. trading data combined. |
||||||
| 2016 Dividends per Share |
||||||
| Payment Month |
CDN$ |
US$(1) |
||||
| January |
$ |
0.03 |
$ |
0.02 |
||
| February |
0.03 |
0.02 |
||||
| March |
0.03 |
0.02 |
||||
| First Quarter Total |
$ |
0.09 |
$ |
0.06 |
||
| (1) US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date. |
||||||
Currency and Accounting Principles
All amounts in this news release are stated in Canadian dollars unless otherwise specified. All financial information in this news release has been prepared and presented in accordance with U.S. GAAP, except as noted below under "Non-GAAP Measures".
Barrels of Oil Equivalent
This news release also contains references to "BOE" (barrels of oil equivalent). Enerplus has adopted the standard of six thousand cubic feet of gas to one barrel of oil (6 Mcf: 1 bbl) when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. The foregoing conversion ratios are based on an energy equivalency conversion method primarily applicable at the burner tip and do not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading.
Presentation of Production Information
Under U.S. GAAP oil and gas sales are generally presented net of royalties and U.S. industry protocol is to present production volumes net of royalties. Under Canadian industry protocol oil and gas sales and production volumes are presented on a gross basis before deduction of royalties. In order to continue to be comparable with its Canadian peer companies, the summary results contained within this news release presents Enerplus' production and BOE measures on a before royalty company interest basis. All production volumes and revenues presented herein are reported on a "company interest" basis, before deduction of Crown and other royalties, plus Enerplus' royalty interest.
Readers are cautioned that the average initial production rates contained in this news release are not necessarily indicative of long-term performance or of ultimate recovery.
FORWARD-LOOKING INFORMATION AND STATEMENTS
This news release contains certain forward-looking information and statements ("forward-looking information") within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "guidance", "ongoing", "may", "will", "project", "should", "believe", "plans", "budget", "strategy" and similar expressions are intended to identify forward-looking information. In particular, but without limiting the foregoing, this news release contains forward-looking information pertaining to the following: expected 2016 average production volumes and the anticipated production mix; the proportion of anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting funds flow; the results from drilling programs and the timing of related production; oil and natural gas prices and differentials and commodity and foreign exchange risk management programs in 2016 and in the future; expectations regarding realized oil and natural gas prices; anticipated cash and non-cash G&A, share based compensation and financing expenses; operating and transportation costs; capital spending levels in 2016, anticipated drilling and completions program, and the expected impact on production levels; potential future asset impairments; future debt and working capital levels and debt to funds flow ratios; future acquisitions and dispositions, including timing thereof, production and reduction of asset retirement obligations associated therewith and expected proceeds therefrom; expected gains in respect to our repurchase of a portion of senior notes and asset divestments; anticipated amount of interest expense savings in respect to our repurchase of senior notes; expectations regarding measures to preserve financial strength, including effectiveness thereof and amounts of anticipated savings therefrom; and the amount of future cash dividends that may be paid to shareholders.
The forward-looking information contained in this news release reflects several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will conduct its operations and achieve results of operations as anticipated; that Enerplus' development plans will achieve the expected results; current commodity price and cost assumptions; the general continuance of current or, where applicable, assumed industry conditions; the continuation of assumed tax, royalty and regulatory regimes; the accuracy of the estimates of Enerplus' reserves and resources volumes; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus' capital and operating requirements, and dividend payments as needed; availability of third party services; and the extent of its liabilities. In addition, Enerplus' 2016 revised guidance is based on the following assumptions: WTI of US$42.38/bbl, NYMEX gas price of US$2.28/Mcf, and AECO gas price of $1.72/GJ, and USD/CDN exchange rate of 1.29. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
The forward-looking information included in this news release is not a guarantee of future performance and should not be unduly relied upon. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information including, without limitation: changes, including future decline, in commodity prices; changes in realized prices for Enerplus' products; changes in the demand for or supply of Enerplus' products; unanticipated operating results, results from Enerplus' capital spending activities or production declines; curtailment of Enerplus' production due to low realized prices or lack of adequate infrastructure; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans by Enerplus or by third party operators of Enerplus' properties; increased debt levels or debt service requirements; Enerplus' inability to comply with covenants under its bank credit facility and senior notes; changes in estimates of Enerplus' oil and gas reserves and resources volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; failure to complete any anticipated acquisitions or divestitures; and certain other risks detailed from time to time in Enerplus' public disclosure documents (including, without limitation, those risks identified in its AIF and Form 40-F at December 31, 2015).
NON-GAAP MEASURES
In this news release, we use the terms "funds flow" and "debt to funds flow ratio" as measures to analyze operating performance, leverage and liquidity. "Funds flow" is calculated as net cash generated from operating activities but before changes in non-cash operating working capital and asset retirement obligation expenditures. "Debt to funds flow ratio" is calculated as total debt net of cash, divided by a trailing 12 months of funds flow. In addition, "senior debt to EBITDA" is used to determine Enerplus' compliance with financial covenants under its bank credit facility and outstanding senior notes. Calculation of these terms is described in Enerplus Corporation's First Quarter 2016 MD&A under the "Liquidity and Capital Resources" section.
Enerplus believes that, in addition to net earnings and other measures prescribed by U.S. GAAP, the terms "funds flow" and "debt to funds flow" are useful supplemental measures as they provide an indication of the results generated by Enerplus' principal business activities. However, these measures, and "senior debt to EBITDA" measures, are not measures recognized by U.S. GAAP and do not have a standardized meaning prescribed by U.S.GAAP. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers. For reconciliation of these measures to the most directly comparable measure calculated in accordance with U.S. GAAP, and further information about these measures, see disclosure under "Non-GAAP Measures" in Enerplus' First Quarter 2016 MD&A.
Electronic copies of Enerplus Corporation's First Quarter 2016 MD&A and Financial Statements, along with other public information including investor presentations, are available on its website at www.enerplus.com. Shareholders may, upon request, receive a printed copy of our audited financial statements at any time. Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation
please contact Investor Relations at 1-800-319-6462 or email [email protected].
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