CALGARY, May 10, 2019 /CNW/ – Enerplus Corporation (“Enerplus” or the “Company”) (TSX & NYSE: ERF) today reported its first quarter 2019 operating and financial results. First quarter 2019 cash flow from operating activities was $109.0 million and adjusted funds flow was $168.8 million. First quarter net income was $19.2 million, or $0.08 per share, and adjusted net income was $72.5 million, or $0.30 per share.
HIGHLIGHTS
- Strong pricing in the Bakken and Marcellus helped drive first quarter adjusted funds flow of $168.8 million
- 2019 production guidance increased to 97,000 to 101,000 BOE per day with 53,500 to 56,000 barrels per day of liquids production
- Mid-point implies 10% year-over-year liquids production growth (13% per share)
- Oil growth underway with second quarter liquids production expected to be approximately 15% higher than the first quarter
- Visibility to meaningful free cash flow in the second half of 2019 based on current forward commodity prices
- Repurchased approximately $35 million of the Company’s stock year-to-date with plans to accelerate share repurchases, based on current market conditions
- 2019 capital spending guidance range narrowed to $590 to $630 million (from $565 to $635 million) following the continued optimization of operational plans
- Significant financial flexibility; total debt net of cash was $363.8 million leading to a net debt to adjusted funds flow ratio of 0.5 times
“Our 2019 plans remain on track,” stated Ian C. Dundas, President and Chief Executive Officer. “As anticipated, we saw production decline in the first quarter as a result of our 2018 investment profile which was front-half weighted. However, the growth we had projected as we moved past the first quarter is now well underway. With solid operational momentum established, we anticipate robust growth going forward.”
Dundas continued, “With our operational plan delivering sustainable, double-digit oil production growth, we will continue to maintain capital spending discipline and prioritize free cash flow generation and return of capital to shareholders. With this in mind, and given our strong liquidity position and the compelling value we currently see in our shares, we plan to accelerate share repurchases under our normal course issuer bid. Additionally, we plan to allocate a meaningful percentage of our expected free cash flow in the second half of the year towards share repurchases, based on current market conditions.”
FIRST QUARTER FINANCIAL AND OPERATIONAL SUMMARY
Production
Production in the first quarter averaged 88,583 BOE per day, including oil and natural gas liquids production of 45,488 barrels per day (90% oil). First quarter production declined 9% from the prior quarter as a result of the Company’s 2018 investment profile which included only modest capital activity in the fourth quarter.
With strong well performance in North Dakota and the Marcellus driving growth and momentum into the second quarter, Enerplus remains well positioned relative to its 2019 production targets. The Company is increasing its annual production guidance to 97,000 to 101,000 BOE per day (from 94,000 to 100,000 BOE per day) including liquids production of 53,500 to 56,000 barrels per day (from 52,500 to 56,000 barrels per day).
Second quarter production is expected to average 97,500 to 100,000 BOE per day, with liquids production of 51,500 to 53,000 barrels per day.
Adjusted Funds Flow and Adjusted Net Income
First quarter adjusted funds flow was $168.8 million compared to $214.3 million in the fourth quarter of 2018. First quarter adjusted net income was $72.5 million ($0.30 per share) compared to $102.2 million ($0.42 per share) in the fourth quarter of 2018. The quarter-over-quarter decreases in adjusted funds flow and adjusted net income were primarily due to lower oil production in the first quarter. Adjusted funds flow in the fourth quarter also benefitted from a $27.2 million Alternative Minimum Tax refund.
Pricing Realizations and Cost Structure
Enerplus’ realized Bakken oil price differential averaged US$3.25 per barrel below WTI in the first quarter, an improvement from US$5.60 per barrel below WTI in the prior quarter due to the return of normal refining activity levels in the U.S. Midwest. For the remainder of 2019, Enerplus has fixed physical differential sales of approximately 19,000 barrels per day of Bakken oil production at US$1.90 per barrel below WTI, including a portion which is sold directly into the US Gulf Coast that utilizes the Company’s firm capacity on the Dakota Access Pipeline. Enerplus’ remaining production is sold on a monthly basis into the highest netback markets available. The Company is maintaining its annual average Bakken differential guidance of US$4.00 per barrel below WTI.
The Company’s first quarter realized Marcellus natural gas price differential was US$0.13 per Mcf above NYMEX, compared to US$0.34 below NYMEX during the prior quarter. The premium differential to NYMEX in the quarter was driven by strong weather-related demand and the Company’s fixed physical basis sales at markedly higher levels than the settled benchmarks. Increased takeaway capacity from additional pipelines brought into service also supported the strong first quarter Marcellus pricing. Differentials have weakened following the first quarter due to the seasonality of pricing and demand in the northeastern U.S. markets. Enerplus expects its realized differentials for the remainder of the year to moderate from the first quarter and is maintaining its full year average Marcellus differential guidance of US$0.30 per Mcf below NYMEX.
First quarter operating expenses were $8.75 per BOE, an increase from $6.99 per BOE in the fourth quarter largely due to lower first quarter production. With production growth underway following the first quarter decline, operating costs per BOE are expected to be lower during the remainder of 2019. The Company is maintaining its full year operating cost guidance of $8.00 per BOE.
First quarter transportation and cash general and administrative (“G&A”) expenses were both largely in line with the Company’s annual 2019 guidance. First quarter transportation costs were $3.92 per BOE and cash G&A expenses were $1.55 per BOE. Enerplus’ 2019 guidance for these items remains unchanged.
Capital Expenditures and Balance Sheet Position
Exploration and development capital spending in the first quarter was $160.8 million and was associated with drilling 17.1 net wells and bringing 6.8 net wells on production across the Company’s operations. Capital spending is expected to increase in the second quarter primarily due to a higher number of well completions in North Dakota compared to the first quarter.
Enerplus has narrowed its 2019 capital budget range to $590 to $630 million (from $565 to $635 million previously) following the continued optimization of its operational plans in North Dakota. The Company expects to complete and bring approximately 35 net operated wells on production in 2019 at Fort Berthold.
Total debt net of cash at March 31, 2019 was $363.8 million. Total debt was comprised of $682.8 million of senior notes outstanding. The Company was undrawn on its $800 million bank credit facility and had a cash balance of $319.0 million. Enerplus’ net debt to adjusted funds flow ratio was 0.5 times at the quarter-end.
Share Repurchase
During the first quarter, the Company repurchased 1.7 million shares at an average share price of $11.43 for a cost of $19.8 million under its normal course issuer bid (“NCIB”). In total, including repurchases made subsequent to the end of the first quarter and up to May 8, 2019, the Company has repurchased 3.0 million shares in 2019 at an average share price of $11.61 for total consideration of $34.8 million.
Enerplus renewed its NCIB commencing on March 26, 2019 for a period of twelve months. The NCIB renewal allows the Company to repurchase up to 16.7 million shares, representing approximately $190 million based on its most recent closing share price.
ASSET ACTIVITY
Average Daily Production(1)
Three months ended March 31, 2019 |
||||
Crude Oil (Mbbl/d) |
Natural Gas |
Natural gas (MMcf/d) |
Total Production (Mboe/d) |
|
Williston Basin |
31.3 |
3.4 |
25.2 |
38.9 |
Marcellus |
– |
– |
209.0 |
34.8 |
Canadian Waterfloods |
8.8 |
0.1 |
3.1 |
9.4 |
Other(2) |
1.0 |
0.9 |
21.3 |
5.5 |
Total |
41.1 |
4.4 |
258.6 |
88.6 |
(1) |
Table may not add due to rounding. |
(2) |
Comprises DJ Basin and non-core properties in Canada. |
Summary of Wells Brought On-Stream(1)
Three months ended March 31, 2019 |
|||||
Operated |
Non-Operated |
||||
Gross |
Net |
Gross |
Net |
||
Williston Basin |
3 |
3.0 |
1 |
0.5 |
|
Marcellus |
– |
– |
13 |
1.9 |
|
Canadian Waterfloods |
1 |
1.0 |
– |
– |
|
Other(2) |
– |
– |
2 |
0.5 |
|
Total |
4 |
4.0 |
16 |
2.8 |
(1) |
Table may not add due to rounding. |
(2) |
Comprises DJ Basin and non-core properties in Canada. |
Williston Basin
Williston Basin production averaged 38,916 BOE per day (80% oil) during the first quarter of 2019, down from 47,420 BOE in the prior quarter. The sequential quarterly decline was due to modest capital activity in the fourth quarter of 2018 during which Enerplus brought one well on production. First quarter Williston Basin production was comprised of 35,889 BOE per day in North Dakota and 3,027 BOE per day in Montana.
In the first quarter, Enerplus brought a three-well (100% working interest) pad on production at Fort Berthold. The average peak 30-day production rate per well was 1,900 BOE per day (74% oil, on a three-stream basis) with an average completed lateral length of 9,600 feet per well.
The Company drilled 15 gross operated wells (95% average working interest) in the first quarter.
Marcellus
Marcellus production averaged 209 MMcf per day during the first quarter, approximately flat from the previous quarter.
Thirteen gross non-operated wells (14% average working interest) were brought on-stream during the quarter. The average peak 30-day production rate per well was 22 MMcf per day with an average completed lateral length per well of 7,700 feet.
The Company participated in drilling nine gross non-operated wells (2% average working interest) during the first quarter.
2019 Guidance Updates
The Company has revised its 2019 production and capital spending guidance ranges, with changes noted in the table below. In addition, production guidance for the second quarter of 2019 has been provided.
2019 Guidance
Capital spending |
$590 to $630 million (from $565 to $635 million) |
Average annual production |
97,000 to 101,000 BOE/day (from 94,000 to 100,000 BOE/day) |
Average annual crude oil and natural gas liquids production |
53,500 to 56,000 bbls/day (from 52,500 to 56,000 bbls/d) |
Q2 2019 production |
97,500 to 100,000 BOE/d |
Q2 2019 liquids production |
51,500 to 53,000 bbls/day |
Average royalty and production tax rate |
25% |
Operating expense |
$8.00/BOE |
Transportation expense |
$4.00/BOE |
Cash G&A expense |
$1.50/BOE |
2019 Full-Year Differential/Basis Outlook (1)
U.S. Bakken crude oil differential (compared to WTI crude oil) |
US$(4.00)/bbl |
Marcellus natural gas sales price differential (compared to NYMEX natural gas) |
US$(0.30)/Mcf |
(1) |
Excluding transportation costs. |
Risk Management
Enerplus continues to manage price risk through commodity hedging. Enerplus has an average of 24,170 barrels per day of crude oil protected for the remainder of 2019 and 16,000 barrels per day protected in 2020.
For natural gas, Enerplus has 90,000 Mcf per day of natural gas production protected from April 1 to October 31, 2019.
Commodity Hedging Detail (As at May 8, 2019)
WTI Crude Oil |
NYMEX Natural Gas |
||||
Apr 1 – Jun 30, |
Jul 1, – Sep 30, |
Oct 1, – Dec 31, |
Jan 1, – Dec 31, |
Apr 1 – Oct 31, |
|
Swaps |
|||||
Sold Swaps |
– |
– |
– |
– |
$2.85 |
Volume (bbls/d or Mcf/d) |
– |
– |
– |
– |
90,000 |
Three-Way Collars |
|||||
Sold Puts |
$44.50 |
$44.64 |
$44.64 |
$46.88 |
– |
Volume (bbls/d or Mcf/d) |
23,500 |
24,500 |
24,500 |
16,000 |
– |
Purchased Puts |
$54.59 |
$54.81 |
$54.81 |
$57.50 |
– |
Volume (bbls/d or Mcf/d) |
23,500 |
24,500 |
24,500 |
16,000 |
– |
Sold Calls |
$65.52 |
$65.95 |
$65.99 |
$72.50 |
– |
Volume (bbls/d or Mcf/d) |
23,500 |
24,500 |
24,500 |
16,000 |
– |
(1) |
The total average deferred premium spent on the three-way collars is US$1.59/bbl from April 1, 2019 to December 31, 2020. |
Q1 2019 Conference Call Details
A conference call hosted by Ian C. Dundas, President and CEO will be held at 9:00 AM MT (11:00 AM ET) today to discuss these results. Details of the conference call are as follows:
Date: |
Friday, May 10, 2019 |
Time: |
9:00 AM MT (11:00 AM ET) |
Dial-In: |
587-880-2171 (Alberta) |
1-888-390-0546 (Toll Free) |
|
Conference ID: |
61757440 |
Audiocast: |
https://event.on24.com/wcc/r/1981813/7620DBA091F49B654D572072C9A79E1E |
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:
Replay Dial-In: |
1-888-390-0541 (Toll Free) |
Replay Passcode: |
757440 # |
SELECTED FINANCIAL AND OPERATING RESULTS
SELECTED FINANCIAL RESULTS |
Three months ended |
|||||
2019 |
2018 |
|||||
Financial (000’s) |
||||||
Net Income |
$ |
19,158 |
$ |
29,637 |
||
Cash Flow from Operating Activities |
108,951 |
159,300 |
||||
Adjusted Funds Flow(4) |
168,755 |
155,162 |
||||
Dividends to Shareholders – Declared |
7,162 |
7,320 |
||||
Total Debt Net of Cash(4) |
363,771 |
291,978 |
||||
Capital Spending |
160,793 |
151,472 |
||||
Property and Land Acquisitions |
3,025 |
12,272 |
||||
Property Divestments |
466 |
6,970 |
||||
Net Debt to Adjusted Funds Flow Ratio(4) |
0.5x |
0.5x |
||||
Financial per Weighted Average Shares Outstanding |
||||||
Net Income – Basic |
$ |
0.08 |
$ |
0.12 |
||
Net Income – Diluted |
0.08 |
0.12 |
||||
Weighted Average Number of Shares Outstanding (000’s) – Basic |
238,922 |
243,874 |
||||
Weighted Average Number of Shares Outstanding (000’s) – Diluted |
241,298 |
249,191 |
||||
Selected Financial Results per BOE(1)(2) |
||||||
Oil & Natural Gas Sales(3) |
$ |
44.70 |
$ |
42.91 |
||
Royalties and Production Taxes |
(10.48) |
(10.41) |
||||
Commodity Derivative Instruments |
1.32 |
1.33 |
||||
Cash Operating Expenses |
(8.75) |
(7.02) |
||||
Transportation Costs |
(3.92) |
(3.52) |
||||
Cash General and Administrative Expenses |
(1.55) |
(1.72) |
||||
Cash Share-Based Compensation |
(0.17) |
(0.25) |
||||
Interest, Foreign Exchange and Other Expenses |
(0.68) |
(1.05) |
||||
Current Income Tax Recovery/(Expense) |
0.69 |
(0.01) |
||||
Adjusted Funds Flow(4) |
$ |
21.16 |
$ |
20.26 |
SELECTED OPERATING RESULTS |
Three months ended |
|||||
2019 |
2018 |
|||||
Average Daily Production(2) |
||||||
Crude Oil (bbls/day) |
41,105 |
37,443 |
||||
Natural Gas Liquids (bbls/day) |
4,383 |
4,085 |
||||
Natural Gas (Mcf/day) |
258,568 |
261,310 |
||||
Total (BOE/day) |
88,583 |
85,080 |
||||
% Crude Oil and Natural Gas Liquids |
51% |
49% |
||||
Average Selling Price (2)(3) |
||||||
Crude Oil (per bbl) |
$ |
66.56 |
$ |
69.67 |
||
Natural Gas Liquids (per bbl) |
19.15 |
28.13 |
||||
Natural Gas (per Mcf) |
4.38 |
3.50 |
||||
Net Wells Drilled |
17 |
14 |
(1) |
Non-cash amounts have been excluded. |
(2) |
Based on Company interest production volumes. See “Presentation of Production Information” below. |
(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 this news release. |
Three months ended |
||||||
Average Benchmark Pricing |
2019 |
2018 |
||||
WTI crude oil (US$/bbl) |
$ |
54.90 |
$ |
62.87 |
||
Brent (ICE) crude oil (US$/bbl) |
63.90 |
67.18 |
||||
NYMEX natural gas – last day (US$/Mcf) |
3.10 |
3.00 |
||||
USD/CDN average exchange rate |
1.33 |
1.26 |
Share Trading Summary |
CDN(1) – ERF |
U.S.(2) – ERF |
||||
For the three months ended March 31, 2019 |
(CDN$) |
(US$) |
||||
High |
$ |
12.55 |
$ |
9.47 |
||
Low |
$ |
10.12 |
$ |
7.44 |
||
Close |
$ |
11.20 |
$ |
8.41 |
(1) |
TSX and other Canadian trading data combined. |
(2) |
NYSE and other U.S. trading data combined. |
2019 Dividends per Share |
CDN$ |
US$(1) |
|||
First Quarter Total |
$ |
0.03 |
$ |
0.02 |
|
Total Year to Date |
$ |
0.03 |
$ |
0.02 |
(1) |
CDN$ dividends converted at the relevant foreign exchange rate on the payment date. |