Enerplus Announces Third Quarter 2016 Results and Preliminary 2017 Outlook
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' Third 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, Nov. 14, 2016 /CNW/ - Enerplus Corporation ("Enerplus" or the "Company") (TSX & NYSE: ERF) is pleased to announce its results from operations for the third quarter of 2016 and preliminary 2017 outlook.
HIGHLIGHTS:
- Third quarter production averaged 92,077 BOE per day, with 42,598 barrels per day of liquids
- 25% reduction in third quarter operating expenses per BOE compared to the same period in 2015
- Positive initial results from recent Fort Berthold high density test, with average production tracking above type curve expectations
- Preliminary 2017 capital budget of $400 million; approximately 70% allocated to North Dakota with the addition of a second drilling rig
- Projecting 2017 North Dakota production growth of 25% and total Company liquids growth of approximately 15% (on a Q4 2016 to Q4 2017 basis)
- Increased 2017 crude oil hedge protection to 17,500 barrels per day
- Canadian waterflood portfolio optimization with the accretive acquisition of approximately 3,800 BOE per day (45% liquids) of high net-back production, with strong secondary recovery growth potential (closing expected November 2016)
"Enerplus' third quarter results demonstrate our continued success in reducing the company's cost structure and driving margin expansion," commented Ian C. Dundas, President & CEO. "Combined with our top quartile capital efficiencies and balance sheet strength, Enerplus is well positioned to reinitiate growth in 2017. Our preliminary 2017 capital budget of $400 million is largely focused on accelerating liquids production which is expected to grow approximately 15% on a Q4 2016 to Q4 2017 basis. Importantly, our capital plans are predicated on profitable and sustainable growth; we expect our capital spending and dividends to be approximately balanced with internally generated cash flow at WTI US$50 per barrel," concluded Dundas.
THIRD QUARTER FINANCIAL RESULTS SUMMARY
Production averaged 92,077 BOE per day during the quarter, including 42,598 barrels per day of crude oil and natural gas liquids. Third quarter production decreased by 2% compared to the prior quarter as Canadian production was impacted by a previously announced divestment at the end of second quarter. Production performance from the Williston Basin and Marcellus remained strong despite relatively few wells brought on-stream in the quarter. Williston Basin production was largely flat from the previous quarter at approximately 33,000 BOE per day, while Marcellus production increased by 5%, averaging 205 MMcf per day.
Enerplus is reaffirming its 2016 annual average production guidance of 93,000 BOE per day (the mid-point of its previous guidance of 92,000 – 94,000 BOE per day) and is narrowing its liquids production guidance range to 43,000 – 44,000 barrels per day (from 43,000 – 45,000 barrels per day) primarily due to weather related delays to completions activity in North Dakota.
Enerplus continues to forecast sequentially lower fourth quarter 2016 production before reinitiating growth in 2017. Fourth quarter production is still expected to average approximately 89,000 BOE per day. Volumes in the fourth quarter are expected to be impacted by approximately 1,500 BOE per day of curtailed production in the Marcellus due to low natural gas prices, and price related shut-ins and minor non-core divestments affecting Canadian gas production by a combined 1,000 BOE per day. These fourth quarter production losses are expected to be offset by strong North Dakota production and the Canadian waterflood acquisition which is projected to close in November 2016.
Enerplus recorded a net loss of $100.7 million ($0.42 per share) in the third quarter, compared to a net loss of $168.6 million ($0.77 per share) in the previous quarter. The third quarter net loss was impacted by a non-cash impairment charge of $61.0 million and a non-cash valuation allowance on our deferred tax asset as a result of the decline in the twelve month trailing average commodity prices.
Enerplus generated third quarter funds flow of $80.1 million, up 5% from the previous quarter, primarily due to higher realized crude oil and natural gas prices and lower operating expenses, partially offset by lower production volumes and lower realized commodity hedging gains.
Enerplus' realized oil price for the third quarter averaged $47.93 per barrel, or US$8.24 per barrel below WTI, compared to US$9.53 per barrel below WTI in the previous quarter. The improved price relative to WTI primarily resulted from a tighter Bakken differential due to declining basin production and strong local refinery demand. Enerplus' realized Bakken differential averaged US$6.39 per barrel below WTI in the third quarter, compared to US$8.23 per barrel in the previous quarter.
Natural gas price realizations averaged $2.12 per Mcf, or US$1.19 per Mcf below NYMEX, compared to US$0.80 per Mcf below NYMEX in the previous quarter. The weaker natural gas price relative to NYMEX primarily resulted from a wider Marcellus differential due to high regional storage inventories combined with seasonal weakness in demand. Enerplus' realized Marcellus differential averaged US$1.19 per Mcf below NYMEX in the third quarter, compared to US$0.76 per Mcf below NYMEX in the previous quarter.
Capital spending for the three and nine months ended September 30, 2016 was $60.3 million and $151.7 million respectively, with the majority directed to the Company's crude oil assets. Enerplus is maintaining its full year 2016 capital expenditure guidance of $215 million.
For the fourth consecutive quarter, Enerplus has reduced its operating expenses. Third quarter operating expenses were $6.64 per BOE, 6% lower than the prior quarter and 25% lower compared to the same period in 2015. Operating expenses for the nine months ended September 30, 2016 were $7.31 per BOE. Enerplus is lowering its full year 2016 guidance for operating expenses to $7.50 per BOE (from $7.90 per BOE) to reflect the performance to date with an expectation that fourth quarter operating expenses per BOE will trend higher, due to lower production volumes and a higher liquids weighting in the production mix.
G&A expenses continued to trend down in the third quarter as a result of the Company's focus on cost control and the reduction to staffing levels throughout 2015 and to date in 2016. Third quarter cash G&A expenses were $1.58 per BOE, 8% lower than the prior quarter and 29% lower compared to the same period in 2015. Cash G&A expenses for the nine months ended September 30, 2016 were $1.79 per BOE. Accordingly, Enerplus is lowering its full year 2016 guidance for cash G&A expenses to $1.80 per BOE (from $1.95 per BOE).
Third quarter transportation costs were $3.39 per BOE, an increase of 18% from the prior quarter primarily due to the addition of a 30,000 MMBtu per day Marcellus related firm interstate transportation commitment that came into effect in August 2016, delivering to higher priced markets.
Enerplus closed the quarter with a strong balance sheet. At quarter-end, total debt net of cash was $654.1 million comprised of $729.1 million of senior notes outstanding less $75.0 million in cash. Enerplus' $800 million bank credit facility was undrawn. At September 30, 2016, Enerplus' senior debt to adjusted EBITDA ratio was 1.3 times and its debt to funds flow ratio was 2.2 times.
PRODUCTION AND CAPITAL SPENDING(1)
| Three months ended |
Nine months ended |
|||||||||
| September 30, 2016 |
September 30, 2016 |
|||||||||
| Average Production |
Capital Spending |
Average Production |
Capital Spending |
|||||||
| Crude Oil & NGLs (bbls/day) |
Volumes |
($ millions) |
Volumes |
($ millions) |
||||||
| Canada |
13,527 |
$ |
8.0 |
14,806 |
$ |
34.2 |
||||
| United States |
29,071 |
$ |
45.1 |
29,025 |
$ |
97.3 |
||||
| Total Crude Oil & NGLs (bbls/day) |
42,598 |
$ |
53.1 |
43,831 |
$ |
131.5 |
||||
| Natural Gas (Mcf/day) |
||||||||||
| Canada |
68,604 |
$ |
0.1 |
82,622 |
$ |
0.2 |
||||
| United States |
228,270 |
$ |
7.2 |
221,527 |
$ |
20.1 |
||||
| Total Natural Gas (Mcf/day) |
296,874 |
$ |
7.3 |
304,149 |
$ |
20.3 |
||||
| Company Total (BOE/day) |
92,077 |
$ |
60.3 |
94,523 |
$ |
151.7 |
||||
| (1) Table may not add due to rounding |
||||||||||
NET DRILLING ACTIVITY(1)– for the three months ended September 30, 2016
| Wells |
Wells |
|||
| Crude Oil |
Drilled |
On-stream |
||
| Canada |
- |
- |
||
| United States |
6.6 |
2.8 |
||
| Total Crude Oil |
6.6 |
2.8 |
||
| Natural Gas |
||||
| Canada |
- |
- |
||
| United States |
- |
0.8 |
||
| Total Natural Gas |
- |
0.8 |
||
| Company Total |
6.6 |
3.6 |
||
| (1) Table may not add due to rounding |
||||
2016 GUIDANCE UPDATE
Updated 2016 guidance is provided below.
| Summary of 2016 Expectations |
Revised Guidance |
Previous Guidance |
||
| Capital spending |
$215 million |
$215 million |
||
| Average annual production |
93,000 BOE/day |
92,000 – 94,000 BOE/day |
||
| Crude oil and natural gas liquids volumes |
43,000 – 44,000 barrels/day |
43,000 – 45,000 barrels/day |
||
| Average royalty and production tax rate |
22% |
22% |
||
| Operating expenses |
$7.50/BOE |
$7.90/BOE |
||
| Transportation expense |
$3.15/BOE |
$3.10/BOE |
||
| Cash G&A expenses |
$1.80/BOE |
$1.95/BOE |
WATERFLOOD ACQUISITION
Subsequent to the quarter, and as part of Enerplus' portfolio optimization activity, the Company entered into an agreement to acquire an operated (100% working interest), high-netback, light oil producing asset with significant secondary recovery growth potential. The asset is located in the Ante Creek area of Alberta with existing production of approximately 3,800 BOE per day (45% liquids). The purchase price is approximately $110 million, net of anticipated closing adjustments, and will be financed with existing cash on the balance sheet and the Company's bank credit facility. Enerplus sees potential to significantly increase crude oil production from the asset within 24 months with only a modest capital investment. The transaction is expected to be accretive to Enerplus on all key metrics including funds flow per debt adjusted share and production per debt adjusted share. The transaction is expected to close in November 2016.
Concurrently, and consistent with the portfolio optimization activities undertaken over the last several years, the Company continues to explore opportunities to divest additional non-core properties.
2017 PRELIMINARY OUTLOOK
Enerplus is committed to a financially disciplined, returns focused strategy which will drive profitable and sustainable growth for shareholders. With the Company's improving cost structure driving margin expansion and its strong capital efficiencies, Enerplus plans to accelerate crude oil growth in 2017 with a capital program largely focused on North Dakota. Enerplus has secured a second operated drilling rig at Fort Berthold commencing operations in January 2017, along with the majority of pressure pumping services for the program. Enerplus has retained significant flexibility to reduce activity levels should commodity prices weaken materially.
Enerplus' preliminary outlook for 2017 capital is $400 million, with approximately 70% targeted for development in North Dakota. This level of spending, along with the Company's dividend commitments, are expected to be largely balanced with internally generated cash flow in 2017 based on commodity prices of US$50 per barrel WTI and US$3.00 per Mcf NYMEX.
To support its capital program, Enerplus has increased its average 2017 crude oil hedge position to 17,500 barrels per day. Additionally, the Company estimates that it has protected approximately 50% of its 2017 capital costs from escalation through contracting.
On a fourth quarter 2016 to fourth quarter 2017 basis, Enerplus expects to grow its North Dakota production by 25% and total Company liquids production by approximately 15%. As a result of the higher expected liquids weighting in the Company's 2017 production mix, Enerplus estimates its 2017 operating expense will trend towards $8.00 per BOE.
Enerplus expects to provide further details of its 2017 capital plans in late 2016.
ASSET ACTIVITY
Williston Basin
Williston Basin production averaged 32,970 BOE per day (88% liquids) during the third quarter comprised of 28,884 BOE per day in North Dakota and 4,086 BOE per day in Montana. Capital spending in the Williston Basin was $45.1 million in the third quarter. The Company continued to operate one drilling rig at Fort Berthold in the third quarter and drilled six gross-operated wells and brought on-stream two gross-operated wells. The two operated on-stream wells had an average initial 30-day production rate of 1,030 BOE per day (84% crude oil). Current average gross operated well costs (drill, complete, tie-in and facilities) for a 10,000 foot lateral well with a high intensity completion are US$8 million.
At the end of the third quarter 2016, Enerplus had approximately 12 net drilled uncompleted wells at Fort Berthold.
Subsequent to the third quarter, Enerplus initiated a three-well density test targeting tighter well spacing than the Company's current 1,400 foot interwell spacing pattern. The test wells are comprised of two Middle Bakken wells spaced at 500 feet offset by one First Bench Three Forks well at 700 feet. The wells have been producing for approximately 20 days with average production rates exceeding type curve expectations. Although this production data is early-time, it is directionally positive and Enerplus will continue to monitor the wells' performance to better understand the implications for higher well density. Enerplus is planning additional well density tests throughout 2017.
In addition to further well density testing, Enerplus will continue to optimize its completions design in 2017, testing both higher and lower proppant volumes around its base design of 1,000 lbs per lateral foot.
Enerplus has secured a second operated drilling rig to commence operations in January 2017, along with pressure pumping services for the 2017 program.
Canadian Waterfloods
Third quarter production from the Canadian waterfloods averaged 14,743 BOE per day (83% liquids), an 11% decrease from the second quarter of 2016 primarily due to a previously announced divestment which closed in June 2016. Capital spending in the third quarter was $8.0 million, predominately related to polymer and waterflood maintenance activities.
Marcellus
Third quarter production from the Marcellus averaged 205 MMcf per day, a 5% increase from the second quarter of 2016 due to continued strong well performance. There was limited activity in the Marcellus in the third quarter with capital spending of $7.2 million delivering 0.8 net well completions.
At the end of the third quarter 2016, Enerplus had approximately 5 net drilled uncompleted wells in the Marcellus.
In October 2016, natural gas pricing weakness in Northeast Pennsylvania led to production curtailment in the Marcellus. The low natural gas prices primarily resulted from high regional storage inventories combined with seasonal weakness in demand. Enerplus estimates fourth quarter Marcellus production will be impacted by approximately 1,500 BOE per day due to curtailment. With the subsequent improvement in gas prices, the curtailed volumes were brought back online in November 2016.
Risk Management
Enerplus continues to protect a portion of funds flow through commodity hedging. The Company has increased its crude oil hedge position in 2017 consistent with its capital spending plans and waterflood acquisition. Enerplus has also begun to establish positions in the 2018 and 2019 periods. In addition to being hedged on over 13,000 barrels per day in the fourth quarter of 2016, Enerplus has an average of 17,500 barrels per day protected through swaps and collar structures in 2017.
For natural gas, Enerplus has approximately 58,400 Mcf per day protected in the fourth quarter of 2016, and 50,000 Mcf per day protected in 2017 using a combination of swaps and collar structures.
Commodity Hedging Detail (As at November 1, 2016)
| WTI Crude Oil (US$/bbl) |
NYMEX Natural Gas |
|||||||||||||
| Oct 1, 2016 – |
Jan 1, 2017 – |
Jul 1, 2017 – |
Jan 1, 2018 – |
Jan 1, 2019 – |
Oct 1, 2016 – Dec 31, 2016 |
Jan 1, 2017 – |
||||||||
| Swaps |
||||||||||||||
| Sold Swaps |
$ |
52.33 |
$ |
52.50 |
$ |
52.50 |
$ |
53.73 |
$ |
53.73 |
$ |
2.51 |
- |
|
| Volume (bbls/d or Mcf/d) |
1,326 |
2,000 |
2,000 |
3,000 |
3,000 |
33,424 |
- |
|||||||
| 3 Way Producer Collars |
||||||||||||||
| Sold Puts |
$ |
45.09 |
$ |
38.94 |
$ |
39.48 |
$ |
41.00 |
- |
$ |
2.50 |
$ |
2.06 |
|
| Volume (bbls/d or Mcf/d) |
12,000 |
14,000 |
17,000 |
1,000 |
- |
25,000 |
50,000 |
|||||||
| Purchased Puts |
$ |
57.82 |
$ |
50.29 |
$ |
50.41 |
$ |
54.00 |
- |
$ |
3.00 |
$ |
2.75 |
|
| Volume (bbls/d or Mcf/d) |
12,000 |
14,000 |
17,000 |
1,000 |
- |
25,000 |
50,000 |
|||||||
| Sold Calls |
$ |
71.75 |
$ |
61.14 |
$ |
60.41 |
$ |
62.00 |
- |
$ |
3.75 |
$ |
3.41 |
|
| Volume (bbls/d or Mcf/d) |
12,000 |
14,000 |
17,000 |
1,000 |
- |
25,000 |
50,000 |
|||||||
Q3 2016 Conference Call Details
A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00AM MT (11:00AM ET) today to discuss these results. Details of the conference call are as follows:
| Date: |
Monday, November 14, 2016 |
| Time: |
9:00 AM MT (11:00 AM ET) |
| Dial-In: |
647-427-7450 |
| 1-888-231-8191 (toll free) |
|
| Audiocast: |
http://event.on24.com/r.htm?e=1285370&s=1&k=2FDBC91307007D1EF8C151424AE3C958 |
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: |
96185756 |
SELECTED FINANCIAL RESULTS
| Three months ended |
Nine months ended |
|||||||||||
| 2016 |
2015 |
2016 |
2015 |
|||||||||
| Financial (000's) |
||||||||||||
| Funds Flow(4) |
$ |
80,101 |
$ |
120,845 |
$ |
197,875 |
$ |
390,427 |
||||
| Dividends to Shareholders |
7,214 |
30,944 |
28,225 |
109,238 |
||||||||
| Net Income/(Loss) |
(100,689) |
(292,666) |
(442,909) |
(898,416) |
||||||||
| Debt Outstanding - net of cash |
654,071 |
1,226,552 |
654,071 |
1,226,552 |
||||||||
| Capital Spending |
60,277 |
88,923 |
151,673 |
403,912 |
||||||||
| Property and Land Acquisitions |
3,777 |
2,005 |
7,674 |
758 |
||||||||
| Property Divestments |
111 |
11,865 |
280,614 |
203,378 |
||||||||
| Debt to Funds Flow Ratio(4) |
2.2x |
2.0x |
2.2x |
2.0x |
||||||||
| Financial per Weighted Average Shares Outstanding |
||||||||||||
| Net Income/(Loss) |
$ |
(0.42) |
$ |
(1.42) |
$ |
(2.00) |
$ |
(4.36) |
||||
| Weighted Average Number of Shares Outstanding(000's) |
240,483 |
206,243 |
221,843 |
206,100 |
||||||||
| Selected Financial Results per BOE(1)(2) |
||||||||||||
| Oil & Natural Gas Sales(3) |
$ |
27.20 |
$ |
27.04 |
$ |
23.69 |
$ |
28.17 |
||||
| Royalties and Production Taxes |
(6.20) |
(6.01) |
(5.20) |
(5.93) |
||||||||
| Commodity Derivative Instruments |
1.17 |
5.31 |
2.75 |
7.36 |
||||||||
| Cash Operating Expenses |
(6.64) |
(8.69) |
(7.33) |
(8.77) |
||||||||
| Transportation Costs |
(3.39) |
(3.03) |
(3.05) |
(2.94) |
||||||||
| General and Administrative Expenses |
(1.58) |
(2.24) |
(1.79) |
(2.21) |
||||||||
| Cash Share-Based Compensation |
(0.03) |
0.35 |
(0.07) |
(0.08) |
||||||||
| Interest, Foreign Exchange and Other Expenses |
(1.07) |
(2.47) |
(1.37) |
(2.72) |
||||||||
| Current Income Tax Recovery |
(0.01) |
1.59 |
0.01 |
0.56 |
||||||||
| Funds Flow(4) |
$ |
9.45 |
$ |
11.85 |
$ |
7.64 |
$ |
13.44 |
||||
SELECTED OPERATING RESULTS
| Three months ended September 30, |
Nine months ended September 30, |
|||||||||||
| 2016 |
2015 |
2016 |
2015 |
|||||||||
| Average Daily Production(2) |
||||||||||||
| Crude Oil (bbls/day) |
37,717 |
44,888 |
38,764 |
41,809 |
||||||||
| Natural Gas Liquids(bbls/day) |
4,881 |
5,061 |
5,067 |
4,652 |
||||||||
| Natural Gas (Mcf/day) |
296,876 |
365,071 |
304,150 |
359,611 |
||||||||
| Total(BOE/day) |
92,077 |
110,794 |
94,523 |
106,396 |
||||||||
| % Crude Oil & Natural Gas Liquids |
46% |
45% |
46% |
44% |
||||||||
| Average Selling Price(2)(3) |
||||||||||||
| Crude Oil (per bbl) |
$ |
47.93 |
$ |
48.22 |
$ |
41.92 |
$ |
50.21 |
||||
| Natural Gas Liquids(per bbl) |
13.85 |
13.51 |
13.53 |
18.60 |
||||||||
| Natural Gas (per Mcf) |
2.12 |
2.08 |
1.79 |
2.24 |
||||||||
| Net Wells drilled |
7 |
8 |
24 |
44 |
||||||||
| (1) |
Non-cash amounts have been excluded. |
| (2) |
Based on Company interest production volumes. See "Basis of Presentation" section in the Third 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". |
| Three months ended September 30, |
Nine months ended |
|||||||||||
| Average Benchmark Pricing |
2016 |
2015 |
2016 |
2015 |
||||||||
| WTI crude oil (US$/bbl) |
$ |
44.94 |
$ |
46.43 |
$ |
41.33 |
$ |
51.00 |
||||
| AECO natural gas – monthly index (CDN$/Mcf) |
2.20 |
2.80 |
1.85 |
2.80 |
||||||||
| AECO natural gas – daily index (CDN$/Mcf) |
2.32 |
2.90 |
1.85 |
2.77 |
||||||||
| NYMEX natural gas – last day (US$/Mcf) |
2.81 |
2.77 |
2.29 |
2.80 |
||||||||
| USD/CDN exchange rate |
1.31 |
1.31 |
1.32 |
1.26 |
||||||||
| Share Trading Summary |
CDN(1)-ERF |
U.S.(2)-ERF |
||||
| For the three months ended September 30, 2016 |
(CDN$) |
(US$) |
||||
| High |
$ |
10.06 |
$ |
7.82 |
||
| Low |
$ |
7.43 |
$ |
5.61 |
||
| Close |
$ |
8.42 |
$ |
6.41 |
||
| (1) |
TSX and other Canadian trading data combined. |
| (2) |
NYSE and other U.S. trading data combined. |
| 2016 Dividends per Share |
||||||
| Payment Month |
CDN$ |
US$(1) |
||||
| First Quarter Total |
$ |
0.09 |
$ |
0.06 |
||
| Second Quarter Total |
$ |
0.03 |
$ |
0.03 |
||
| July |
$ |
0.01 |
$ |
0.01 |
||
| August |
0.01 |
0.01 |
||||
| September |
0.01 |
0.01 |
||||
| Third Quarter Total |
$ |
0.03 |
$ |
0.03 |
||
| Total Year to Date |
$ |
0.15 |
$ |
0.12 |
||
| (1) |
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 and 2017 average production volumes and the anticipated production mix; the proportion of our anticipated oil and gas production that is hedged and the effectiveness of such hedges in protecting our funds flow; the results from our drilling program and the timing of related production; oil and natural gas prices and differentials and our commodity risk management programs in 2016 and beyond; expectations regarding our realized oil and natural gas prices; future royalty rates on our production and future production taxes; anticipated cash and non-cash G&A, share-based compensation and financing expenses; operating and transportation costs; capital spending levels in 2016 and 2017 and its impact on our production level and land holdings; our future royalty and production and cash taxes; our deferred income taxes; future debt and working capital levels and debt to funds flow ratios.
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, our 2016 guidance contained in this news release is based on the following: a WTI price of US$43.64/bbl, a NYMEX price of US$2.52/Mcf, an AECO price of $2.01/GJ and a USD/CDN exchange rate of 1.32. Our 2017 preliminary outlook contained in this news release is based on the following: a WTI price of US$50.00/bbl, a NYMEX price of US$3.00/Mcf, an AECO price of $2.95/GJ and a USD/CDN exchange rate of 1.30. 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 adjusted 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 Third 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 adjusted 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' Third Quarter 2016 MD&A.
Electronic copies of Enerplus Corporation's Third 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. For further information, please contact Investor Relations at 1-800-319-6462 or email [email protected].
Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
Ian C. Dundas
President & Chief Executive Officer
Enerplus Corporation
SOURCE Enerplus Corporation
ENERPLUS CORPORATION, The Dome Tower, Suite 3000, 333 - 7th Avenue SW, Calgary, Alberta, T2P 2Z1, T. 403-298-2200, F. 403-298-2211, www.enerplus.com
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