CALGARY, ALBERTA–(Marketwired – Aug. 12, 2013) – RMP Energy Inc. (“RMP” or the “Company“) (TSX:RMP) is pleased to report its results for the second quarter of 2013. For the three months ended June 30, 2013, RMP reported funds from operations of $21.2 million ($0.20 per basic share) on revenue of $35.6 million and average daily production of 6,852 barrels of oil equivalent. Highlights are as follows:
|Financial Highlights||Three Months Ended June 30,||Six Months Ended June 30,|
|(thousands except share and per boe data) (6:1 oil equivalent conversion)||2013||2012||% Change||2013||2012||% Change|
|Petroleum and natural gas revenue (1)||35,617||16,971||110||68,214||36,145||89|
|Funds from operations (2)||21,221||9,644||120||41,349||19,960||107|
|Per share – basic||0.20||0.10||100||0.39||0.21||86|
|Per share – basic and diluted||0.05||0.03||67||0.06||0.05||20|
|E&D capital expenditures||18,601||18,308||2||57,685||37,224||55|
|Total capital expenditures||18,814||17,686||6||57,942||36,668||58|
|Net debt (3) – period end||72,767||63,295||15||72,767||63,295||15|
|Weighted average basic shares||106,996,438||96,834,196||10||105,631,348||96,741,441||9|
|Weighted average diluted shares||112,498,170||96,834,196||16||110,664,767||96,741,441||14|
|Issued and outstanding shares (4)||109,556,090||98,190,855||12||109,556,090||98,190,855||12|
|Average daily production:|
|Natural gas (Mcf/d)||19,755||17,178||15||19,019||17,519||9|
|Liquids (Oil and NGLs) (bbls/d)||3,560||1,900||87||3,620||1,975||83|
|Oil equivalent (boe/d)||6,852||4,763||44||6,790||4,895||39|
|% Liquids (Oil and NGLs)||52||%||40||%||30||53||%||40||%||33|
|Average sales price(1) :|
|Natural gas ($/Mcf)||3.90||2.09||87||3.71||2.22||67|
|Liquids (Oil and NGLs) ($/bbl)||88.32||79.24||11||84.64||80.91||5|
|Oil equivalent ($/boe)||57.12||39.16||46||55.51||40.57||37|
|Operating expenses ($/boe)||6.84||7.12||(4||)||7.38||7.91||(7||)|
|Operating netback (5) ($/boe)||37.97||26.69||42||37.34||26.55||41|
|Wells drilled: gross (net)||1 (1.0||)||2 (1.4||)||(50||)||7 (7.0||)||7 (6.4||)||–|
- Petroleum and natural gas (“P&NG“) revenue and average sales pricing includes: any realized gains or losses from risk management commodity contract settlements.
- Funds from operations does not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS“). Please refer to the Reader Advisories at the end of the news release.
- Net debt is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.
- As of August 12, 2013, common shares outstanding are 109,592,756.
- Operating netback is not a recognized measure under IFRS. Please refer to the Reader Advisories at the end of the news release.
Second Quarter 2013 Operating and Financial Highlights
- Record average daily production of 6,852 boe/d, weighted 52% towards light oil and NGLs, representing a 44% increase over the second quarter 2012 level of 4,763 boe/d. During the quarter, the Company’s operational preparedness with additional oil tank storage assisted with minimizing the impact of road bans associated with spring break-up surface conditions, which provided for better-than-anticipated crude oil production at Ante Creek. However, significant wet field conditions in late-June and into July delayed the Company’s third quarter drilling and completions operations by approximately three weeks. Please refer to Updated 2013 Market Guidance section of this news release.
- Funds from operations of $21.2 million ($0.20 per basic share) for the three months ended June 30, 2013, representing a 120% increase (100% per share) from the funds from operations for the second quarter of 2012. An increase in both light oil and natural gas production and pricing, in conjunction with lower operating costs, contributed to higher funds from operations in the second quarter of 2013. However, the full benefit of such was tempered by higher royalties, as discussed below. Field operating netbacks for the second quarter of 2013 were $37.97/boe, as compared to the $26.69/boe in the second quarter of 2012 and $36.69/boe in the preceding first quarter of 2013.
- In the second quarter, the Company incurred capital expenditures of $18.8 million. RMP drilled one (1.0 net) horizontal oil well at Waskahigan and successfully completed the well in late-July. Additionally, as previously disclosed on May 10, 2013, the Company acquired a total of 22.75 gross sections (16.0 net) of land in the Montney light oil fairway in the Ante Creek area of West Central Alberta, in exchange for 3.4 million common shares of RMP with an ascribed total value $13.5 million.
- Net debt as of June 30, 2013 was $72.8 million, representing less than one times net debt-to-annualized second quarter funds from operations. Effective May 8, 2013, the Company’s borrowing limit under its bank credit facility was increased to $140 million from $110 million, facilitating additional financial flexibility and liquidity. Approximately $74 million is presently drawn against the credit facility. On May 31, 2013, the Company closed a non-brokered, $5.0 million flow-through common share private placement in respect of Canadian development expenses, pursuant to which 1.0 million common shares were issued at $5.00 per share.
- Petroleum and natural gas (“P&NG“) revenue for the second quarter amounted to $35.6 million (including a realized gain on risk management commodity contracts of $27 thousand). The Company’s realized crude oil discount differential to the Canadian-dollar converted WTI price averaged approximately $5.78/bbl during the quarter, as compared to $15.58/bbl in the second quarter of 2012. Differentials in the forward market for the Company’s Waskahigan and Ante Creek crude oil pricing continue to be sub-$10.00/bbl, with pricing at a current average discount of approximately $9.00/bbl estimated for the balance of this year.
- Net income for the second quarter amounted to $5.1 million, as compared to $2.7 million of net earnings in the second quarter of 2012. In the second quarter of 2012, a non-cash unrealized gain on risk management contracts of $4.9 million was recognized, as compared to a unrealized loss on risk management contracts of $14 thousand in the second quarter of 2013, distorting the quarterly income comparison.
- Petroleum and natural gas royalties amounted to $6.0 million (17% of P&NG sales excluding a realized gain on risk management commodity contracts), as compared to $1.7 million (10% of P&NG sales) in the second quarter of 2012 and $4.2 million (13% of P&NG sales) in the preceding first quarter of 2013. The increase in royalties is primarily attributable to the Ante Creek field, wherein the wells produced in the second quarter became no longer eligible for the volume-based, 5% Crown royalty cap available under the Alberta Government drilling incentive program due to strong production performance of the Ante Creek wells. Additionally, in the second quarter of 2013, a thirteenth-month Alberta Crown royalty charge of approximately $351 thousand was recognized.
- Corporate operating costs of $6.84/boe decreased by 4% on a per boe basis, when compared to operating costs for the second quarter 2012 period of $7.12/boe. Year-to-date operating costs at RMP’s Waskahigan and Ante Creek fields were $6.38/boe and $3.51/boe, respectively, a significant achievement given the oil-weighted nature of the Company’s flagship properties.
Second Quarter 2013 Operations Update
Spring break-up field conditions in the second quarter curbed the Company’s drilling and completions field activities. RMP drilled one 100% working interest horizontal oil well (8-3-64-23W5) with successful completion operations undertaken in late-July. Subsequent to the end of the second quarter, the Company drilled another 100% working interest horizontal oil well (5-9-64-23W5) and is currently drilling the 8-10-64-23W5 horizontal well (100% working interest). For the balance of this year, RMP intends to drill an additional three horizontal light oil wells (3.0 net). The Company’s acreage position at Waskahigan encompasses 37 contiguous sections at 100% working interest, providing for a future light oil drilling inventory of approximately 120 locations.
Ante Creek Operations
At Ante Creek, during the second quarter, the Company did not conduct any drilling operations. However, RMP is planning to commence drilling operations and spud the 16-25-66-24W5 horizontal well (1.0 net), which will be the Company’s sixth well on the property. Overall, the Company has successfully drilled, completed and tied-in a total of five (5.0 net) highly productive Montney horizontal oil wells at Ante Creek.
Presently, third-party solution gas compression is insufficient to facilitate the simultaneous production of all five wells. Additionally, third-party infrastructure experienced run rate time of approximately 90% during the second quarter due to operational issues.
The following outlines the production results to-date of RMP’s Ante Creek wells and their current status (through to August 7, 2013). After producing a cumulative 600,000 bbls of oil from the area, these wells are still flowing at restricted rates with wellhead chokes and no artificial lift.
- 13-27 well flow tested new oil at 1,150 bbls/d and 3.0 MMcf/d of associated solution gas (final 24 hours of flow test), as previously disclosed on March 13, 2013. Reported production in table reflects new oil produced during flow test.
As previously disclosed on May 13, 2013, the Company is proceeding with the strategic installation of a wholly-owned pipeline inter-connect between its Ante Creek and Waskahigan properties, including the expansion of RMP’s Ante Creek surface field facilities. Oil fluid handling capacity at the Ante Creek 4-36 Battery will be expanded to 10,000 bbls/d, with solution gas handling increased to 22 MMcf/d. Barring any unforeseen delays, the pipeline inter-connect and related field equipment is scheduled to be commissioned and operational in late-February 2014. Upon commissioning of the Ante Creek pipeline, the Company anticipates corporate productive capacity to aggregate to at least 9,000 boe/d.
During the second quarter and subsequent to June 30, 2013, the Company placed purchase orders for capital equipment of approximately $11 million related to the Company’s planned expansion of the Ante Creek 4-36 Battery. RMP is scheduled to take delivery and title to this equipment at various times beginning in the latter part of the third quarter of 2013.
For the balance of this year, the Company intends to drill an additional three (3.0 net) horizontal light oil wells at Ante Creek, including the 16-25 well. As a result of RMP’s strategic Ante Creek undeveloped land acquisition on May 10, 2013, the Company feels that it has established ‘critical mass’ in the area for the purpose of future delineation and development drilling activities. The Company’s acreage position at Ante Creek encompasses 28.75 sections (22.0 net), providing for a significant, future light oil drilling inventory.
At Grizzly, to the southeast of Waskahigan, RMP tied-in its first quarter-drilled 4-5-63-22W5 horizontal well (1.0 net) to an area operator’s oil battery facility, however, solution gas handling issues at a Simonette gas plant downstream of this battery is preventing this well from commencing production. The Company expects this well to be on-production on or about October 1, 2013, following a scheduled three week gas plant turnaround in September, at a production rate similar to that of a typical Waskahigan type-well. At Grizzly, RMP holds a 100% working interest position on 12.25 sections of acreage, providing the Company with another Montney light oil resource project to delineate and develop. In the fourth quarter of this year, RMP intends to drill its third exploration well at Grizzly (8-29-63-22W5).
Updated 2013 Market Guidance
Despite a delayed commencement of drilling and completion field operations in the third quarter of this year due to abnormally wet surface conditions, strong drilling and production performance over the first half of 2013 has facilitated an increase in the Company’s estimated fiscal 2013 average daily production range to approximate 6,800 boe/d (weighted 54% light crude oil and NGLs), from the originally-guided 6,000 to 6,500 boe/d production forecast. This increased production target represents a 27% increase over RMP’s 2012 average daily production. This production forecast assumes limited solution gas processing capacity at Ante Creek of approximately 3.7 MMcf/d, which is insufficient to facilitate the concurrent production of all of RMP’s Ante Creek wells.
The Company is expecting full year capital investment in 2013 to aggregate to approximately $133 million, comprised of an exploration and development program of approximately $90 million, $13.5 million for the Ante Creek land expansion purchased for RMP common shares, and approximately $29 million of capital expenditures associated with the Ante Creek pipeline and infrastructure project anticipated to be incurred by December 31, 2013. This capital project is forecasted as staged expenditures to be incurred over the next eight months based on scheduled progress. The Company has added to its original 2013 capital budget an exploration well at Grizzly to further delineate the 12.25 sections of 100% working interest acreage RMP holds. This well is not budgeted to be placed on-production in 2013. Additionally, the Company plans to participate in a 97 square kilometer proprietary 3D seismic program at Waskahigan with two other area participants.
The Company’s funds from operations for 2013 is estimated at $83 million or $0.77 per basic share, which represents a significant increase of 61% and 48%, respectively, over fiscal 2012 funds from operations. Net debt at December 31, 2013 is estimated at $106 million after funding most of the Ante Creek pipeline and infrastructure project, providing for $34 million of projected, un-utilized borrowing capacity entering 2014.
In order to ensure the Company’s cash flow is protected from lower-than-budgeted commodity prices, the following commodity hedge positions are currently outstanding:
|Jul. 1, 2013 – Dec. 31, 2013 (remaining term)||Swap||1,750 bbls||WTI Nymex||Cdn. $ 97.70/bbl|
|Jan. 1, 2014 – Dec. 31, 2014 : Fiscal 2014||Swap||750 bbls||WTI Nymex||Cdn. $ 98.24/bbl|
|Jan. 1, 2014 – Mar. 31, 2014 : Q1 2014||Swap||250 bbls||WTI Nymex||Cdn. $ 102.55/bbl|
|Jul. 1, 2013 – Oct. 31, 2013 (remaining term)||Swap||5,000 GJs||AECO 5A||Cdn. $ 3.05/GJ|
Additionally, the Company has one interest rate swap in-place in order to fix a base interest rate on its existing banker’s acceptance borrowings. The purpose of this instrument is to mitigate existing exposure to unfavourable market interest rate changes. RMP is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. The underlying base interest rate, under RMP’s bank credit facility, is subject to additional stamping fees ranging from 2.00% to 3.25% depending upon the debt-to-cash flow ratio calculated at the Company’s previous quarter-end.
|Jul. 1, 2013 – May 29, 2015 (remaining term)||Swap||Cdn. $ 30,000,000||BA-CDOR||1.39%|
The Company’s interim condensed consolidated financial statements and associated Management’s Discussion and Analysis (“MD&A“) for the three and six months ended June 30, 2013 are available on RMP’s website at www.rmpenergyinc.com within “Investors” under “Financials”. Additionally, these documents will have been filed by the close of business today, on the Company’s profile on the System for Electronic Document Analysis and Retrieval (“SEDAR“). These documents can be retrieved electronically from the SEDAR system by accessing RMP’s public filings under “Search for Public Company Documents” within the “Search Database” module at www.sedar.com.
|bbl or bbls||barrel or barrels||Mcf/d||thousand cubic feet per day|
|Mbbl||thousand barrels||MMcf/d||million cubic feet per day|
|bbls/d||barrels per day||Mcf||thousand cubic feet|
|boe||barrels of oil equivalent||MMcf||million cubic feet|
|Mboe||thousand barrels of oil equivalent||Bcf||billion cubic feet|
|boe/d||barrels of oil equivalent per day||psi||pounds per square inch|
|NGLs||natural gas liquids||kPa||kilopascals|
|WTI||West Texas Intermediate||GJ/d||Gigajoules per day|
Any references in this news release to initial and/or final raw test or production rates and/or “flush” production rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company.
The information in this news release contains certain forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “budget”, “plan”, “continue”, “estimate”, “approximate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, “would” and similar expressions. More particularly and without limitation, this news release contains forward-looking information relating to: 2013 Capital Budget; forecasted average daily production rates for 2013 and upon commissioning of the proposed Ante Creek pipeline in 2014; funds from operations for 2013; production and funds from operations growth rate; liquids-weighting; year-end 2013 estimated net debt and un-utilized borrowing credit capacity; forward market pricing discount for the Company’s Waskahigan and Ante Creek crude oil; the number of drilling locations remaining to be drilled this year in 2013 at Waskahigan, Ante Creek and Grizzly; the number of future drilling locations in the Waskahigan drilling inventory; the current production of the Ante Creek wells, the timing for bringing the Company’s well at Grizzly on-production; the Company’s estimated crude oil and solution gas handling capacity at the Ante Creek 4-36 Battery following the proposed expansion of field infrastructure and pipeline installation; the total capital cost of this expansion and pipeline and the staged timing of the capital expenditures; and the estimated commissioning and operational date of the Ante Creek pipeline and related field infrastructure expansion, behind-pipe production at Ante Creek.
These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond the Company’s control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; volatility in market prices for crude oil, natural gas and NGLs; foreign exchange currency and interest rate fluctuation; stock market volatility and market valuations; liabilities inherent in oil and natural gas operations; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry ; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; and obtaining required approvals of regulatory authorities. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that the Company will derive from them. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary statement. Except as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statements.
In this news release RMP has adopted a standard for converting thousands of cubic feet (“mcf“) of natural gas to barrels of oil equivalent (“boe“) of 6 mcf:1 boe. Use of boes may be misleading, particularly if used in isolation. The boe rate is based on an energy equivalent 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 than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.
As an indicator of the Company’s performance, the term funds from operations contained within this news release should not be considered as an alternative to, or more meaningful than, cash flow from operating, financing or investing activities, as determined in accordance with IFRS. This term is not a recognized measure, does not have a standardized meaning nor is it a financial measure under IFRS. Funds from operations is widely accepted as a financial indicator of an exploration and production company’s ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by shareholders and investors in the valuation, comparison and investment recommendations of companies within the natural gas and crude oil exploration and production industry. Funds from operations, as disclosed within this news release, represents cash flow from operating activities before: decommissioning obligation cash expenditures and changes in non-cash working capital from operating activities. The Company presents funds from operations per share whereby per share amounts are calculated consistent with the calculation of earnings per share.
Net debt refers to outstanding bank debt plus working capital deficit or less any working capital surplus (excludes current unrealized amounts pertaining to risk management commodity contracts). Net debt is not a recognized measure under IFRS and does not have a standardized meaning.
Field operating netback or operating netback refers to realized wellhead revenue less royalties, operating expenses and transportation costs per boe. Field operating netback or operating netback is not a recognized measure under IFRS and does not have a standardized meaning.