Enerplus Corporation announces guidance for 2013 and the acquisition of additional low decline, light oil interests in Montana.
Acquisition of Bakken Interests in Montana
Consistent with our strategy of consolidating core positions within our portfolio, Enerplus has agreed to enter into an agreement to acquire an additional 20% working interest in our operated leases in the Sleeping Giant area in the Elm Coulee field in Richland County, Montana for approximately US$131 million (approximately US$121 million after estimated closing adjustments of US$10 million). By investing approximately half of the proceeds from the sale of our Manitoba assets, we expect to replace the sold production, improve the concentration of our asset base and improve our operating metrics.
The acquisition is complementary to our existing operations in Sleeping Giant where we currently own an operated 70% working interest. This is a mature light oil property with an average decline rate of 14%. Our internal reserves assessment has identified a total of 6.2 million BOE of proved plus probable reserves associated with the acquisition and daily production of approximately 1,550 BOE/day (both of which are weighted 80% to light crude oil). The transaction has attractive acquisition metrics of 4.2 times annual funds flow after estimated closing adjustments, $23.00/BOE of proved plus probable reserves including future development capital and is expected to be 4% accretive to funds flow in 2013 (2% on a debt-adjusted basis). This light oil property has current netbacks of approximately $50/BOE with low operating costs averaging $5.50/BOE in 2012. We do not expect any increases in general and administrative costs as a result of the acquisition.
We believe there is additional upside potential in this field through production optimization, refracs and limited infill drilling. With approximately 400 million barrels of original oil in place on our operated leases, we are also evaluating the potential for enhanced oil recovery schemes as the current reserve bookings results in a 14% recovery factor. The total crude oil recovered to date is approximately 8%. We anticipate closing the acquisition mid-December, after which Enerplus will own a 90% working interest in the operated leases with production of approximately 7,300 BOE/day. We expect a modest level of capital spending at Sleeping Giant in 2013.
Guidance for 2013
In addition, the Board of Directors of Enerplus has approved a capital spending program for 2013. Highlights of the program are as follows:
- We expect to deliver funds flow growth of over 11% in 2013. On a debt-adjusted basis, funds flow is expected to grow by 6% per share. This growth, along with a current yield of approximately 8%, aligns with our long-term business strategy of providing an attractive total return to investors comprised of both growth and income.
- We are targeting a capital program of $685 million, 20% lower than our estimated spending in 2012, which more closely balances our capital spending and dividends with funds flow.
- We expect production to average between 82,000 BOE/day and 85,000 BOE/day, which at the mid-point of the range, would represent a 2% increase over our estimated 2012 average daily production after adjusting for our recent acquisition and divestment activities. Based upon current cost structures and the commodity price outlook for both crude oil and natural gas in 2013, we believe this is an appropriate level of production growth. We plan to continue to pursue acquisition opportunities in core areas and rationalize non-core assets to enhance our portfolio and profitability.
- With an expected increase in funds flow, combined with a reduced capital spending program and maintenance of our dividend, we expect our adjusted pay-out ratio to improve to approximately 130% net of our Stock Dividend Program (“SDP”). We intend to continue to focus our portfolio and improve our cost structure to enhance the sustainability of our business.
- We have successfully managed our balance sheet throughout 2012. We continue to pursue joint venture opportunities and non-core asset sales in an effort to allow us to enhance shareholder value. Our debt to funds flow ratio is expected to be 1.9 times at the end of 2013 based upon current forward market commodity prices, our estimate of production and costs and before any additional acquisition or divestment activities
- We remain committed to providing a meaningful dividend to investors. Given the steps we have proactively taken to improve the sustainability of our business including the sale of non-core assets and reducing our capital spending plans, we currently have no plans to adjust our monthly dividend. We will continue to review dividend levels in the context of commodity prices, capital spending, cost structures and debt levels.
|Capital Expenditures ($millions)||$850||$685|
|Annual Average Daily Production (BOE/day)||82,000||82,000 – 85,000|
|Oil & Liquids Weighting||49%||50%|
|Exit Production (BOE/day)||85,000 – 88,000||84,000 – 88,000|
|Oil & Liquids Weighting||49%||50%|
|Adjusted Payout Ratio**||190%||130%|
|Debt/Funds Flow at Year-End||1.8x||1.9x|
Based upon forward commodity prices and forecast costs as of November 26, 2012 including the impact of hedging and does not include any acquisition or divestment activities not previously announced. Based upon our current capital spending plans for Q42012, forecast YE2012 debt is approximately $1.1 billion
** Adjusted payout ratio is calculated as the sum of dividends paid to shareholders, net of participation in the Stock Dividend Plan, plus capital expenditures divided by funds flow. See “Non-GAAP Measures” below.
We are targeting a capital spending program of $685 million in 2013. Through this spending, we expect to offset our corporate production decline rate of approximately 24% and grow production modestly by 2%. Approximately 85% of our program is currently planned to be directed to oil and liquids rich natural gas projects, with over 75% directed specifically to crude oil projects. Our capital program is based upon delivering a minimum internal rate of return of 25%.
The Fort Berthold region of North Dakota has delivered significant light oil production growth for Enerplus over the past two years. Through our 2012 drilling program, we have effectively managed our lease expirations in the region and grown production to approximately 14,000 BOE/day during the month of November. We expect to reduce capital spending by 25% to approximately $340 million next year as we focus on improving our costs and efficiencies while still delivering production growth. We’re forecasting average daily production growth of 30% next year over expected 2012 average volumes. We plan to run a two-rig program targeting both the Bakken and Three Forks formations and expect to drill, complete and bring on-stream between 20 to 25 net wells at Fort Berthold next year. The majority of these wells will be long horizontal wells. We expect non-operating spending will represent approximately 15% of our total spending in this area in 2013.
We expect to continue to invest in our oil waterflood properties in Canada next year targeting a capital spending program of approximately $160 million similar to 2012 levels. Under our planned spending, we will continue to invest in drilling projects at Freda Lake in Saskatchewan and Medicine Hat, Giltedge and Pembina in Alberta. Waterflood optimization will remain a focus area as we continue to balance drilling activity with our pressure maintenance programs to effectively manage performance from these fields. Our volumes are expected to be modestly impacted next year as we plan to curtail approximately 400 BOE/day and 2 MMcf/day of natural gas at Pembina early in the first quarter as part of this on-going program. We anticipate that these volumes will be recovered over the course of the next 6 to18 months and believe this will result in better long-term recoveries. Finally, we plan to continue to advance on our existing polymer projects at Medicine Hat and Giltedge. Overall we have been encouraged by the performance of these projects. We plan to evaluate performance over the course of next year and if performance continues as we expect, would be in a position to consider expansion of the program.
We plan to reduce capital spending in the Marcellus region by over 50% to $80 million in 2013 directed to non-operated drilling projects in the northeast region of Pennsylvania. Through this drilling program, we expect to have retained the majority of what we believe to be core non-operated acreage by the end of 2013. We expect continued production growth from 55 MMcf/day currently to roughly 75 MMcf/day as we exit 2013. Given the lower operating costs associated with this production ($0.75/Mcf) and NYMEX based pricing, operating netbacks are currently averaging approximately $2.00/Mcf. As a result, our Marcellus production is expected to contribute to the increase in funds flow in 2013. We anticipate that 25% of our corporate natural gas production volumes will be attributable to the Marcellus in 2013. We continue to see positive results from our drilling program despite the delays associated with infrastructure in the region.
We expect to continue investing in the Deep Basin region in 2013 on both our operated and non-operated leases. Approximately $75 million will be allocated to develop natural gas projects with associated liquids. Based upon our success in the Wilrich play in Alberta in 2012, we are planning an additional 3 to 5 wells next year.
Approximately 75% of our capital spending is expected to be directed to drilling projects with around 90 net wells planned in 2013 with 80 net wells brought on-stream throughout the year. The program is weighted to the first half of the year with about one third of the capital planned for investment in the first quarter. We expect that approximately 75% of our capital spending will be directed to properties where we control the pace and level of spending. We expect to allocate less than $30 million to delineate our undeveloped acreage in 2013.
|2013 Capital Spending Breakdown||2013E
|Development Drilling & Completions||$555|
|Exploration & Seismic||$30|
We expect to review our capital spending program on a regular basis throughout the year in the context of prevailing commodity prices, economic conditions and cost structures and may modify our spending plans as required.
We are forecasting average daily production of 82,000 to 85,000 BOE/day in 2013, a 2% increase over our estimated 2012 average daily production after adjusting for our recent acquisition and divestment activities. Crude oil production is expected to increase in 2013, averaging 38,000 bbls/day, up 2.5% from 2012. Oil production in the Fort Berthold region of North Dakota is expected to grow again in 2013 but at a slower pace than in 2012 given the reduced capital spending plans. Natural gas and natural gas liquids volumes are expected to remain flat year-over-year. The additional natural gas volumes associated with our 2012 Marcellus drilling program are anticipated to come on-stream during the first half of 2013 and are expected to offset the decline in our Canadian conventional natural gas properties. Total natural gas production is expected to average approximately 250 MMcf/day. Approximately 75% of our total production will be operated by Enerplus.
As we plan to spend a greater proportion of our capital spending in the first half of 2013, and given the variability and timing of our non-operated spending, we expect exit production in 2013 to range between 84,000 and 88,000 BOE/day.
Current Daily Production
Daily production during the month of November 2012 is estimated to be 86,000 BOE/day. Given the slow-down in drilling activity, we expect December production will be similar.
Operating costs are expected to average $10.70/BOE, unchanged from 2012 and general and administrative expenses are expected to average $3.40/BOE, up marginally from 2012. We expect our average royalty rate will increase slightly in 2013 due to an improvement in the natural gas price outlook and the increase in production associated with our U.S. operations which have higher royalty rates than our Canadian operations. Royalties are expected to average 21% of revenues. We have sufficient tax pools to shelter our funds flow in Canada in 2013 and beyond, and we expect U.S. cash taxes to be approximately 3% of our U.S. cash flow.
|2013 Forecast Expenses||2013E|
|Operating Costs ($/BOE)||$10.70|
|Cash General & Administrative Expenses ($/BOE)||$3.15|
|Non-cash General & Administrative Expenses ($/BOE)||$0.25|
|Cash Taxes ($MM)||$12|
|Interest Expense ($MM)||$65|
Funds Flow Growth
Based upon current forward commodity prices, we expect funds flow to grow in 2013 by 6% per debt-adjusted share. Improvements in natural gas prices as well as the growing NYMEX based natural gas production in the Marcellus are key factors contributing to this expected growth. Our hedging program is expected to provide support to this increase as we have 57% of our anticipated net oil production volumes hedged at a price of US$100.84 per barrel and 12% of our projected net natural gas volumes swapped at a fixed price of $3.63/Mcf and a further 11% of our projected net natural gas production hedged with put protection at $3.17/Mcf. We estimate that approximately 75% of the net operating income will be generated from our oil plays.
|2013 Sensitivities||Est. effect on 2013
|Change of $5.00/bbl WTI crude oil||$0.14|
|Change of $0.50/Mcf AECO natural gas||$0.18|
|Change of 1,000 BOE/day production||$0.05|
|Change of $0.01 in the US$/CDN$ exchange rate||$0.05|
We have preserved our financial flexibility throughout 2012 through the sale of non-core assets, issuance of long-term debt and a reduction in our dividend. We expect to exit 2012 with a debt-to-funds flow ratio of 1.8 times which we anticipate is at the low end of our peer group. Our adjusted pay-out ratio is expected to drop significantly in 2013 to approximately 130% net of the participation in the SDP. In the context of current commodity prices, we expect a debt-funded shortfall of $200 million (funds flow including participation in the SDP less capital spending and dividends). We expect to continue to divest of non-core assets to offset our funding shortfall and to improve the concentration and focus within our portfolio. Our debt to funds flow ratio is expected to be 1.9 times at the end of 2013 before consideration of any joint venture, asset sale or acquisition activities.
Gordon J. Kerr
President & Chief Executive Officer
Currency, BOE and Operational Information
All dollar amounts or references to “$” in this news release are in Canadian dollars unless specified otherwise. Enerplus has adopted the standard of 6 Mcf:1 BOE when converting natural gas to BOEs. BOEs may be misleading particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Unless otherwise stated, all oil and gas production information and estimates are presented on a gross basis, before deducting royalty interests.
Cautionary Note Regarding Forward-Looking Information and Statements
This news release contains certain forward-looking information and statements (collectively, “forward-looking information”) within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “budget”, “guidance”, “objective”, “ongoing”, “may”, “will”, “project”, “should”, “believe”, “plans”, “intends”, “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 and statements pertaining to the following: future capital spending amounts, the timing and locations of such spending and the types of projects on which such capital will be spent; future growth in production, and cash flow and other anticipated growth opportunities; a financing strategy to fund anticipated capital expenditures, including funds raised from our Stock Dividend Plan; future oil, natural gas liquids and natural gas prices and production levels (including anticipated 2013 average daily and exit production rates), the product mix and sources of such production, and production decline rates; future drilling activities and results and undeveloped land acquisitions; future capital efficiencies, corporate netbacks and cash flow levels; rates of return from our investments; the expected ultimate recovery of oil or gas from a particular well; operating costs, general and administrative expenses and royalty expenses; sales of our non-core properties and the redeployment of proceeds realized therefrom; dividend payments made by Enerplus and the related adjusted payout ratio; the timing and payment of future taxes; our planned commodity risk management program; and future liquidity, debt levels, financial capacity and resources; and the completion of our proposed acquisition of additional working interests in Montana, including the terms and timing thereof.
The forward-looking information contained in this news release reflect several material factors and expectations and assumptions of Enerplus including, without limitation: that Enerplus will achieve operational, production and drilling results as anticipated; anticipated production decline rates; the general continuance of current or, where applicable, assumed industry conditions; commodity prices will remain within Enerplus’ expected range of forecast prices, being the current forward market prices; availability of adequate cash flow, debt and/or equity sources to fund Enerplus’ capital and operating requirements as needed and to pay dividends to shareholders as anticipated; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; availability of willing buyers for the properties proposed to be disposed of; that capital, operating, financing and third party service provider costs will not exceed Enerplus’ current expectations; availability of third party service providers (including drilling rigs and service crews) and cooperation of industry partners; certain foreign exchange rate and other cost assumptions. Enerplus believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable at this time 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; unanticipated operating or drilling results or production declines; potential redeployment of available funding to alternative projects; changes in tax or environmental laws or royalty rates; increased debt levels or debt service requirements; insufficient available cash to pay dividends as currently anticipated; inaccurate estimation of or changes to estimates of Enerplus’ oil and gas reserve and resource volumes and the assumptions relating thereto; limited, unfavourable or no access to debt or equity capital markets; increased costs and expenses; a shortage of third party service providers; the impact of competitors; reliance on industry partners; an inability to agree to terms with potential buyers of investments or assets that may be disposed of; and certain other risks detailed from time to time in Enerplus’ public disclosure documents including, without limitation, those risks identified in our MD&A for the year ended December 31, 2011 and in Enerplus’ Annual Information Form dated March 9, 2012 for the year ended December 31, 2011, copies of which are available on Enerplus’ SEDAR profile at www.sedar.com and which also form part of Enerplus’ annual report on Form 40-F for the year ended December 31, 2011 filed with the United States Securities and Exchange Commission, a copy of which is available at www.sec.gov.
The forward-looking information contained in this news release speaks only as of the date of this news release, and Enerplus assumes no obligation to publicly update or revise such information to reflect new events or circumstances, except as may be required pursuant to applicable laws.
Any financial outlook or future oriented financial information in this news release, as defined by applicable securities legislation, has been approved by management of Enerplus. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s reasonable expectations as to the anticipated results of its proposed business activities for 2013. Readers are cautioned that reliance on such information may not be appropriate for other purposes.
Enerplus utilizes the following terms for measurement within this news release that do not have a standardized meaning or definition as prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other entities
We use the term “adjusted payout ratio” to measure operating performance, leverage and liquidity. We calculate “adjusted payout ratio” is calculated as dividends paid to shareholders net of the participation in the Stock Dividend Plan plus capital expenditures divided by funds flow. The term “adjusted payout ratio” does not have a standardized meaning or definition as prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other entities.
Netback is used to measure operating performance and is calculated by subtracting Enerplus’ expected royalties and operating costs from the anticipated revenues in respect of the relevant properties. The term “netback” does not have a standardized meaning or definition as prescribed by IFRS and therefore may not be comparable with the calculation of similar measures by other entities.