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. Readers are also referred to “Information Regarding Financial and Operational Information” and “Non-GAAP Measures” at the end of this news release for information regarding the presentation of the financial and operational information contained in this news release. A full copy of our third quarter 2013 Financial Statements and MD&A, as well as our 2012 Financial Statements and MD&A, have been filed on our website at www.enerplus.com, under our profile on SEDAR at www.sedar.com and on the EDGAR website at www.sec.gov.
3rd QUARTER HIGHLIGHTS:
- As a result of strong operational performance from our core areas in both Canada and the U.S. daily production during the third quarter averaged just under 88,000 BOE/day, up 8% from the same period last year.
- Production from our North Dakota assets continues to outperform our expectations, increasing by almost 20% during the quarter to a new record level of 18,000 BOE/day, achieving our 2013 exit forecast for these properties one full quarter ahead of expectations.
- Year-to-date, production has averaged 88,318 BOE/day, up 9% from the same period a year ago in spite of divestments earlier in the year, and ahead of our revised guidance of 87,500 BOE/day.
- We generated funds flow of $196 million ($0.98 per share) in the third quarter, up 45% from the third quarter of 2012.
- Our adjusted payout ratio during the quarter fell to 97% and year-to-date is 103%, a significant improvement from the same periods in 2012.
- The majority of our $146 million capital program during the quarter was allocated to our U.S. oil and Canadian waterflood oil assets, where 70% of our drilling program took place. We are seeing improved cost performance in a number of our key operating areas, most notably in Fort Berthold and in the Marcellus.
- Our capital spending program remains on track with our original guidance for 2013 with a focus on maximizing crude oil and liquids production. In the first nine months of 2013, we have spent only two thirds of our annual capital budget yet are exceeding our forecasts for both annual average and exit production, despite the sale of 1,300 BOE/day of non-core production.
- Operating and general and administrative costs per BOE are also on track and we are maintaining our guidance on both metrics for the full year.
- Our financial flexibility has also continued to improve in part from the growth in funds flow and also by our non-core asset sales. The trailing twelve month debt-to-funds flow ratio fell to 1.2 times at the end of September, compared to 1.9 times for the same period last year.
- On October 22, 2013, we announced an additional sale of non-core assets for approximately $105 million before closing adjustments which further focuses our operations, strengthens our balance sheet and improves our financial position.
- With more than 80% of our corporate netback derived from crude oil, we continue to hedge our exposure to crude oil prices to help protect our funds flow and ensure our on-going financial strength. About 74% of our forecast crude oil production, net of royalties, is hedged at just over US$100/bbl for the remainder of 2013. For the first half of 2014, we have price protection on 66% of our forecast crude oil production, net of royalties, at an average price of US$93.70/bbl, while 49% of our forecast crude oil production net of royalties for the second half of 2014 is hedged at US$92.73/bbl. We have 25% of our 2014 forecast natural gas production, net of royalties, hedged at a price of $4.15/Mcf, before considering the acquisition of additional interests in the Marcellus.
- Subsequent to the quarter, we have entered into an agreement to purchase additional interests in our core Marcellus properties for approximately US$153 million before closing adjustments. The acquisition includes 17,000 net acres of land in the northeast region of Pennsylvania and approximately 42 MMcf/day of natural gas production. This acquisition will increase our exit production forecast from 88,000 BOE/day to 95,000 BOE/day.
- In addition, subsequent to the quarter, we have entered into an agreement to sell our Montney interests at Julienne Creek for $130 million. The sale includes 33,300 net acres of land with no associated production or reserves.
|SELECTED FINANCIAL RESULTS|
|Three months ended September 30,||Nine months ended September 30,|
|Cash and Stock Dividends||54,405||53,394||162,199||247,988|
|Debt Outstanding – net of cash||964,577||1,118,569||964,577||1,118,569|
|Property and Land Acquisitions||15,792||7,277||71,451||63,946|
|Debt to Trailing 12 Month Funds Flow||1.2x||1.9x||1.2x||1.9x|
|Financial per Weighted Average Shares Outstanding|
|Weighted Average Number of Shares Outstanding (000’s)||201,117||197,618||200,002||194,753|
|Selected Financial Results per BOE(1)|
|Oil & Gas Sales(2)||$53.61||$43.30||$49.67||$44.10|
|Commodity Derivative Instruments||(1.30)||1.06||0.42||0.11|
|General and Administrative||(2.48)||(2.48)||(2.63)||(2.70)|
|Equity Based Compensation||(0.60)||(0.69)||(0.58)||(0.24)|
|Interest and Other Expenses||(1.78)||(2.56)||(1.78)||(1.40)|
|SELECTED OPERATING RESULTS|
|Three months ended September 30,||Nine months ended September 30,|
|Average Daily Production|
|Crude oil (bbls/day)||38,883||36,810||38,426||35,807|
|Natural gas (Mcf/day)||275,164||247,347||279,212||249,046|
|% Crude Oil & Natural Gas Liquids||48%||49%||47%||49%|
|Average Selling Price(2)|
|Crude oil (per bbl)||$ 96.30||$ 76.41||$ 86.05||$ 78.72|
|NGLs (per bbl)||49.88||47.81||51.48||54.88|
|Natural gas (per Mcf)||2.96||2.20||3.26||2.18|
|Net Wells drilled||15||17||50||70|
(1) Non-cash amounts have been excluded.
(2) Net of oil and gas transportation costs, but before the effects of commodity derivative instruments.
|Three months ended September 30,||Nine months ended September 30,|
|Average Benchmark Pricing|
|WTI crude oil (US$/bbl)||$105.82||$92.22||$98.14||$96.21|
|AECO- monthly index (CDN$/Mcf)||2.82||2.19||3.16||2.18|
|AECO- daily index (CDN$/Mcf)||2.43||2.29||3.05||2.11|
|NYMEX- monthly NX3 index (US$/Mcf)||3.60||2.81||3.68||2.62|
|USD/CDN exchange rate||1.04||1.00||1.02||1.00|
|SHARE TRADING SUMMARY||CDN* – ERF||U.S.** – ERF|
|For the three months ended September 30, 2013||(CDN$)||(US$)|
* TSX and other Canadian trading data combined.
**NYSE and other U.S. trading data combined.
|2013 DIVIDENDS PER SHARE|
|First Quarter Total||$0.27||$0.27|
|Second Quarter Total||$0.27||$0.26|
|Third Quarter Total||$0.27||$0.26|
(1) US$ dividends represent CDN$ dividends converted at the relevant foreign exchange rate on the payment date.
|PRODUCTION AND CAPITAL SPENDING|
|Three months ended
September 30, 2013
|Nine months ended
September 30, 2013
|Crude Oil & NGLs (BOE/day)||Average
|Total Crude Oil & NGLs (BOE/day)||41,868||$101||41,783||$338|
|Natural Gas (Mcf/day)|
|Total Natural Gas (Mcf/day)||275,164||$45||279,212||$120|
|Company Total (BOE/day)||87,729||$146||88,318||$458|
|NET DRILLING ACTIVITY – for the three months ended September 30, 2013|
|Total Crude Oil||11.3||–||11.3||8.0||8.9||–|
|Total Natural Gas||3.9||–||3.9||3.7||2.2||–|
*Wells drilled during the quarter that are pending potential completion/tie-in or abandonment as at September 30, 2013.
**Total wells brought on-stream during the quarter regardless of when they were drilled.
U.S. Crude Oil
We continued to allocate the majority of our capital spending to the Williston Basin, targeting light crude oil from the Bakken and Three Forks oil plays. During the quarter we invested $66 million at Fort Berthold, North Dakota, drilling 6.6 net horizontal wells and bringing 3.2 net horizontal wells on stream. During this period our North Dakota production grew by almost 2,900 BOE/day to a record 18,000 BOE/day, a 19% increase from the last quarter. Combined with our Bakken production from Montana, our U.S. assets now account for more than half of Enerplus’ total crude oil and liquids volumes.
We are also seeing a significant improvement in well performance as we continue to optimize our completion design. Since the start of 2013, we have evolved our completions, moving from ceramic proppant to white sand proppant while increasing the number of frac stages by 40% and the amount of proppant per stage by over 200%. Despite the increase in frac size, our average cost per frac stage has decreased by approximately 15%. More significantly, the average 30 day cumulative initial production in our most recent Bakken and Three Forks wells is 80% or higher than the rates we were achieving at the start of 2013.
We’ve drilled 10.6 net wells in the Bakken and 4.9 net wells in the first bench of the Three Forks to date in 2013 and continue to explore downspacing and testing of the lower benches of the Three Forks in order to expand our drilling inventory.
Canadian Crude Oil
Production from our Canadian oil assets averaged approximately 19,500 BOE/day, down from second quarter results of 21,300 BOE/day largely due to downtime at our Medicine Hat “Glauc C” property and the sale of non-core production earlier in the year.
In Saskatchewan, results on the Ratcliffe trend continued to exceed our expectations. These assets attracted the highest share of investment amongst our waterflood properties during the quarter as we drilled 3.7 net horizontal wells in the area, brought 2 net wells on stream, and continued to invest in infrastructure to support our growing production in the region. Initial production volumes over the first 30 days from these wells are exceeding our type curve expectations by almost 60%, with rates of about 220 bbls/day. We plan on drilling 2 additional gross (1.3 net) wells offsetting these producers during the fourth quarter of 2013.
U.S. Natural Gas
Production from the Marcellus averaged 83 MMcf/day of natural gas during the quarter, ahead of our planned 2013 exit rate of 75 MMcf/day. We continue to be encouraged by strong well performance and as new wells come on stream, we expect to reach record production levels in the fourth quarter. We invested $23 million in the Marcellus during the quarter, which included the drilling of 2.8 net wells and bringing 2.2 net wells on stream. As a result of the production growth achieved year-to-date and an improvement in NYMEX natural gas prices year-over-year, funds flow has increased significantly from the Marcellus with approximately $48 million realized year-to-date. Additionally, well costs have also improved, declining approximately 20% from our original budget expectations. Given the on-going production growth from the Marcellus and lagging infrastructure expansion, differentials in the region continued to widen. Our long-term sales contracts on over 75% of our current production provided us with a degree of protection, resulting in our average realized Marcellus gas price being about US$0.52/Mcf below the NYMEX price during the quarter. Until infrastructure catches up to the burgeoning natural gas supply and new markets open up, we expect that wide differentials will persist in the region.
Canadian Natural Gas
Our Canadian natural gas activities continued to be focused in the Deep Basin region of Alberta where we are advancing our development plans in the Wilrich and continuing to delineate the Duvernay.
Based upon the success of our drilling activity in the Wilrich, we acquired an additional 5,000 net acres in the Minehead area during the third quarter and have moved one dedicated rig to the region to execute our development plans. We plan to drill and complete one well in the fourth quarter and expect to spud a second well which will be completed in early 2014.
As a result of recent drilling activity, Enerplus now has core data from three Duvernay vertical delineation test wells on varying sections of our leases in the Willesden Green area. The core analysis from these wells is positive and in our view supports a range of expected free condensate of 75 – 150 bbls per million cubic feet of natural gas over a significant portion of our acreage block. This data supports our current plan to drill a horizontal re-entry which is underway in one of the vertical tests. We expect to follow with another horizontal well with completion of both wells scheduled in 2014.
Marcellus Acquisition and Montney Disposition Subsequent to the Quarter
Consistent with our strategy to concentrate our portfolio in top tier assets in core areas, we have entered into agreements to add to our U.S. gas position in the Marcellus and to also sell our Montney interests in northeastern British Columbia.
We have entered into an agreement to acquire additional working interests in 17,000 net non-operated acres within our core properties in the Marcellus with current production of approximately 42 MMcf/day of natural gas for approximately US$153 million before closing adjustments.
The acquisition increases our working interest in existing non-operated leases within the northeast region of Pennsylvania. Since entering the play in 2009, well performance from this region has surpassed our expectations and increased our confidence in the productivity and economic viability of the Marcellus. Based upon the drilling results achieved to date, we expect ultimate recoveries (“EUR”) of natural gas in the best areas to range from 10 Bcf to 13.5 Bcf or higher per well. Close to half of the acquired leases are located in 10 Bcf or greater areas and virtually all of the value of the transaction has been attributed to these Tier 1 areas with approximately 44 net future drilling locations.
Approximately 60% of the total leases being acquired are currently held by production. With the majority of our existing core leasehold acreage now held by production, we have seen an improvement in drilling efficiencies to date in 2013 that has resulted in lower well costs. Based upon our expected ultimate recoveries and current well costs of under $7 million, we expect top tier full cycle finding, development and acquisition costs of less than $1.00 per Mcf with attractive recycle ratios.
Upon closing of the acquisition, Enerplus’ core Marcellus acreage will total approximately 60,000 net acres. We plan to more fully outline our capital spending plans when we release our 2014 production and capital forecast in December of this year.
The acquisition is expected to close at the end of November 2013 and as a result will increase our 2013 exit rate guidance from 88,000 BOE/day to 95,000 BOE/day. This increase in natural gas production in 2014 is expected to provide us with the opportunity to continue selling non-core assets and high-grading our portfolio. Our 2013 annual average production and capital spending forecast is not expected to change materially as a result of the acquisition.
We have also entered into an agreement to sell our Montney interests at Julienne Creek for $130 million. While we believe the Julienne Creek asset offers significant scope and scale, the natural gas produced in this area is predominantly dry with very little associated natural gas liquids production. Our core assets in the Williston Basin, our waterfloods, the Marcellus and the Deep Basin (Wilrich and Duvernay) provide us with a deep inventory of future drilling prospects that offer more favourable economics and will enable us to grow production, reserves and cash flow in existing areas in both the near and long-term. Enerplus has invested approximately $50 million building our position in the Montney. The sale includes 33,300 net contiguous acres (100% working interest) with no current production or reserves, representing sale metrics of approximately $3,900 per acre.
Our quarterly results once again reflect the benefits of our multi-year strategy to position Enerplus in top tier resource plays and develop them within a disciplined capital allocation and cost management framework. Our non-core property dispositions continue to help us improve our financial flexibility and enable us to focus our expertise and capital spending within our four core areas. These strategies are driving improved capital efficiencies and achieving sustainable, profitable growth and income for our investors. We plan to continue on this path of value creation for our shareholders.
Q3 Results Live Conference Call
A conference call will be held at 9:00 AM MT (11:00 AM ET) to discuss these results. Details of the conference call are as follows:
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:
|1-855-859-2056 (toll free)|
Electronic copies of our Q3 MD&A and financial statements, along with other public information including investor presentations are available on our website at www.enerplus.com. For further information, please contact Investor Relations at 1-800-319-6462 or email email@example.com.
Follow @EnerplusCorp on Twitter at https://twitter.com/EnerplusCorp.
INFORMATION REGARDING FINANCIAL AND OPERATIONAL INFORMATION
Currency and Production Amounts
All amounts in this news release are stated in Canadian dollars unless otherwise specified. 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. Company interest is not a term defined in Canadian National Instrument 51-101- Standards of Disclosure for Oil and Gas Activities) and may not be comparable to information produced by other entities.
Barrels of Oil Equivalent and Cubic Feet of Gas 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.
See “Non-GAAP Measures” below.
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”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “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: achievement of operational targets for 2013; Enerplus’ expected operating and general and administrative costs and oil and natural gas production volumes for 2013; our average realized crude oil and natural gas prices and future differentials; the proportion of our anticipated oil and natural gas production that is hedged; Enerplus’ financial capacity to support capital spending plans and its dividend; potential asset divestments and acquisitions and the impact of such on our 2013 production; future efficiencies and reserves and production growth from capital spending; future capital and development expenditures and the allocation thereof among our assets; future development and drilling locations, plans and costs; the performance of and future results from Enerplus’ assets and operations, including anticipated production levels, decline rates and future growth prospects; the potential change of our status from “foreign private issuer” to U.S. domestic issuer as of January 1, 2014 and expected changes in our reporting related thereto; and our ability to improve our trading multiple and create significant value for our 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’ operations and development plans will achieve the expected results; the general continuance of current or, where applicable, assumed industry conditions, including third party costs; the continuation of assumed tax, royalty and regulatory regimes; commodity price and cost assumptions; the continued availability of adequate debt and/or equity financing, cash flow and other sources to fund Enerplus’ capital and operating requirements as needed; the continued availability and sufficiency of our funds flow and availability under our bank credit facility to fund our working capital deficiency; the extent of its liabilities; and that Enerplus will be able to complete planned asset sales. 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 in commodity prices; changes in the demand for or supply of Enerplus’ products; unanticipated operating results, results from development plans or production declines; 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; inaccurate estimation of Enerplus’ oil and gas reserves and resources volumes; limited, unfavourable or a lack of access to capital markets; an inability to complete planned asset sales and acquisitions; increased costs; a lack of adequate insurance coverage; the impact of competitors; reliance on industry partners; and certain other risks detailed from time to time in Enerplus’ public disclosure documents (including, without limitation, those risks identified in Enerplus’ Annual Information Form and Form 40-F for the year ended December 31, 2012, filed on SEDAR and EDGAR, respectively, on February 22, 2013).
The forward-looking information contained in this news release speaks only as of the date of this news release, and none of Enerplus or its subsidiaries assume any obligation to publicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.
In this news release, we use the terms “adjusted payout ratio” to analyze operating performance, leverage and liquidity, and “netback” as measures of operating performance. We calculate “adjusted payout ratio” as cash dividends to shareholders, net of our stock dividends (and for 2012 comparative purposes, our DRIP proceeds), plus capital spending (including office capital) divided by funds flow. “Netback” is calculated as oil and gas sales revenues after deducting royalties, operating costs and transportation.
Enerplus believes that, in addition to net earnings and other measures prescribed by IFRS, the term “adjusted payout ratio” and “netback” are useful supplemental measures as they provides an indication of the results generated by Enerplus’ principal business activities. However, these measures are not recognized by GAAP and do not have a standardized meaning prescribed by IFRS. Therefore, these measures, as defined by Enerplus, may not be comparable to similar measures presented by other issuers.
Ian C. Dundas
President & Chief Executive Officer
SOURCE Enerplus Corporation