CALGARY, Aug. 15, 2013 /CNW/ – Pinecrest Energy Inc. (“Pinecrest” or the “Company”) is pleased to announce that it has filed on SEDAR its unaudited financial statements and related Management’s Discussion and Analysis (“MD&A”) for the three and six months ended June 30, 2013. The statements will be available for review atwww.sedar.com or www.pinecrestenergy.com.
Second Quarter 2013 Achievements
Pinecrest is pleased to provide the following update on our achievements during the three months ended June 30, 2013:
- Achieved average production of 3,615 boe per day (97% light oil), an increase of 23% from 2,951 boe per day for the three months ended June 30, 2012;
- Increased funds from operations to $16.4 million ($0.08 per basic and $0.07 per diluted shares outstanding) compared to $15.9 million ($0.07 per basic and diluted shares outstanding) for the quarter ended June 30, 2012;|
- Generated a top quartile field netback of $60.36 per boe for the quarter ended June 30, 2013;
- Completed the conversion of its third (Loon Project #1) waterflood project and started injecting water in the latter part of March 2013. Subsequent to June 30, the Company commenced injection at two more waterflood projects (Red Earth #1 and Evi #3) which brings the active waterflood count to five (four Company operated);
- Reduced average cost to drill, complete, equip and tie-in to $3.8 million per well. Pinecrest has been continuously refining its well design and has most recently achieved a cost savings of approximately $1.4 million per well, compared to the same period in 2012; and
- Completed the installation of compression and gas pipeline required to conserve solution gas from the Otter and Evi fields.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
|June 30||Three months ended||Six months ended|
|2013||2012||% Change||2013||2012||% Change|
|Petroleum and natural gas sales||29,573||22,426||32||63,402||50,617||25|
|Funds flow from operations (1)||16,374||15,866||3||37,753||36,140||5|
|Per share – basic||$0.08||$0.07||14||$0.17||$0.17||–|
|Per share – diluted||$0.07||$0.07||–||$0.16||$0.15||7|
|Per share – basic||$0.02||$0.04||(50)||$0.04||$0.07||(43)|
|Per share – diluted||$0.02||$0.04||(50)||$0.03||$0.06||(50)|
|Net debt and working capital deficit (2)||120,774||6,661||1,713||120,774||6,661||1,713|
|Common Shares Outstanding|
|Weighted average – basic||216,437||214,158||1||217,071||206,622||5|
|Weighted average – diluted||229,474||241,997||(5)||233,977||236,890||(1)|
|Number of days||91||91||181||182|
|Crude oil (bbls/d)||3,467||2,934||18||3,855||3,140||23|
|Natural gas (mcf/d)||561||53||959||418||44||850|
|Barrels of oil equivalent (boe/d-6:1)||3,615||2,951||23||3,963||3,155||26|
|Average realized price(3)|
|Crude oil ($/bbl)||92.40||83.83||10||90.05||88.41||2|
|Natural gas ($/mcf)||3.55||1.58||125||3.22||1.77||82|
|Barrels of oil equivalent ($/boe- 6:1)||89.90||83.51||7||88.40||88.16||–|
|Netback per boe ($)(1)|
|Petroleum and natural gas sales||89.90||83.51||7||88.40||88.16||–|
|Realized gain (loss) on derivative financial
|Production and transportation expenses||(22.31)||(15.08)||48||(20.45)||(14.41)||42|
|Success rate (%)||–||100||–||100||100||–|
|(2)||Includes $3.7 million liability (2012 – $2.8 million asset) related to the fair value of derivative financial instruments|
|(3)||Before the effects of commodity price derivative contracts|
The Company continues to see encouraging results from the two previously announced operated waterflood schemes, Evi – Project #2 (December 20, 2012 commencement) and Loon – Project #1 (March 21, 2013 commencement).
Both schemes have been on continuous injection since start-up with voidage replacement ratios (VRR) monitored and adjusted continuously as fluid production from the schemes steadily increases. The offsetting producing wells in both schemes have been on continuous production with the exception of Evi – Project #2, in which a routine bottomhole pump failure occurred during breakup causing the offsetting producing well to be down for 27 days (which also necessitated an injection rate reduction). As indicated, production continues to incline and water cuts are stable to decreasing as the reservoir is being re-pressurized.
The following table outlines oil production rates and water cuts for the project:
|EVI Project #2||Loon Project #1|
|(1) Voidage Replacement Ratio|
Response time and production increases are within Company expectations. As production continues to increase and the required voidage replacement also increases, the Company anticipates further gains in production rates from these and future Pinecrest operated schemes in the Greater Red Earth area. At year-end, Pinecrest’s active waterflood count will be eight (seven operated) and the Company has identified four schemes for implementation in 2014.
Subsequent to the quarter, water injection commenced in late July on the Company’s operated projects at Evi #3, and Red Earth #1. Injection at both these projects has been continuous and is within the projects designed instantaneous and maximum VRR target of 2:1. Response from these schemes is anticipated in late Q3 to early Q4 2013.
Additionally, field facility construction and injection well conversions are under way at Pinecrest’s three remaining operated waterflood projects in Otter. The Company remains on track for these schemes to begin injection subject to Alberta Energy Regulator (AER) approval, late in the third quarter of 2013, with production response expected late Q4 2013 to Q1 2014.
As planned, there was no drilling or completion activity undertaken during the second quarter. Pinecrest drilled a total of 11 gross (10.3 net) horizontal Slave Point wells in the first quarter of 2013 and all were placed on production byApril 8, 2013. The average cost to drill, complete, equip and tie-in the wells drilled in the first quarter of 2013 was $3.8 million per well, a $1.4 million per well savings as compared to the first quarter of 2012.
The first quarter 2013 well costs represent a significant reduction to Pinecrest’s previous cost structure and are a function of Pinecrest’s modified well design and overall cost reductions in the industry. Additionally, and as previously announced, Pinecrest will be moving forward with its plans to implement a proposed change to its completion method on future wells. Our industry analysis of the Slave Point formation in the Greater Red Earth area confirm the superior performance of the open-hole packer style of completion. We are excited to implement this new system and look forward to achieving further cost reductions as well as reporting our results in the latter half of the year.
Persistent wet weather has delayed the commencement of the Company’s third quarter capital program and increased unscheduled downtime due to limited access. Subsequent to the end of the second quarter drilling operations resumed on August 8, 2013 which is a full month later than originally planned.
Production for the second quarter of 2013 increased by 23% to 3,615 boe per day from 2,951 boe per day for the corresponding period in 2012. Production rates increased as a result of the Company’s successful drilling program along with positive early responses from our waterfloods. Production in the second quarter of 2013 decreased by 16% from 4,315 boe per day in the first quarter of 2013. This decrease is a result of normal reduced activity levels during spring break up, natural production declines, and unscheduled downtime. Natural gas and natural gas liquids production (NGL’s) increased significantly in the second quarter of 2013 as a result of the commissioning of a new compressor and sales gas line earlier in the year. Pinecrest’s commodity mix remains very attractive at 97% oil and NGL’s.
The Company experienced an increase in operating costs associated primarily with the implementation and operation of the waterflood schemes. Once the initial injection facilities have been completed, the Company is focused on reducing operating costs associated with each waterflood installation. Initially, water and power for the injection facilities is supplied via temporary means. Water is trucked to each site and power is supplied using rental generators and diesel fuel. Field electrification is now underway at the Red Earth and Loon fields. By the end of Q4 2013, injection water will be delivered by pipeline to all but one of the Company’s injection schemes, eliminating significant trucking costs.
The Company expects that these initiatives and others currently being implemented will have a positive impact on lowering the Company’s overall operating costs. In addition, costs associated with emulsion trucking will be reduced as the majority of the wells have now been tied into central production facilities. Future emulsion hauling will be subjected to a competitive bidding process.
For the balance of 2013, Pinecrest is targeting total operating expenses (production and transportation costs) of approximately $22 per boe. The implementation of all of Pinecrest’s operating cost initiatives will not be fully realized until Q1 2014.
Current production is approximately 3,200 boed, with approximately 300 boed shut in due to field conditions. The Company expects to average 3,100 – 3,200 boed for the third quarter, while the Company performs a mid-August battery turn around and converts seven producing wells to injectors, all affecting production. The Company expects to spend approximately $16.0 million in capital for the quarter.
OUTLOOK – GREATER RED EARTH AREA, ALBERTA
Pinecrest commenced operations in early 2011 with a minimal production base and has organically grown the Company, almost exclusively, through the drill bit by way of an aggressive capital program focused on the large oil in place Slave Point formation in the Greater Red Earth area. As a result, the corporate decline rate has, at times, mimicked that of a horizontal Slave Point oil well. On average, a Slave Point horizontal oil well will experience a first year natural decline of approximately 65%-70%, which is typical for all tight oil reservoirs. With the licensing and implementation of the seven operated waterfloods, the Company is now transitioning from a high decline production base dominated by newly drilled horizontal wells to a more stable, lower decline asset base. Pinecrest entered 2013 with an estimated annualized monthly decline rate of approximately 55% compared to an estimated current decline rate of 35% and it is expected that this overall decline rate will continue to improve as more waterfloods are commissioned and as our existing wells mature. This reduction in corporate decline rates combined with improving capital efficiencies and a focus on operating cost reductions, allows the Company to grow production while spending significantly less capital in the upcoming years. With the anticipated response of the remaining five operated 2013 waterfloods, the Company expects to generate free cash flow in calendar year 2014.
Since inception, Pinecrest has established itself as one of the dominant interest holders in the high quality Slave Point light oil resource play in the Greater Red Earth area. The Company has over 400 net risked drilling locations on its lands which contain an estimated 580 million barrels of Discovered Oil Initially In Place (1)(2) as of January 31, 2012 with very low recovery to date. Sproule & Associates Ltd. conducted an assessment effective as of January 31, 2012 (the “Assessment”) of Pinecrest’s Contingent Slave Point Oil Resources(3) and has assigned the Company a contingent resource Best Estimate(4)of 67.5 million barrels using, a 13% recovery factor and based on a drilling density of 4 wells per section. The Company believes that significant upside potential, over and above the contingent resource assignment, can be achieved through further infill drilling and water flooding. The Assessment was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NI 51-101(5).
This resource capture is consistent with the Company’s stated strategy of focusing its capital and resources on large light oil accumulations with high netback production, long term upside and the ability to increase recovery factors through the application of horizontal wells, multi-stage fracture stimulations and implementing waterflood recovery schemes. Analogous Slave Point waterfloods in the immediate area have proven to be very effective and have been assigned incremental recovery factors ranging between 50 and 100 percent over primary recovery.
For the balance of 2013, Pinecrest will execute an integrated capital program that will include selectively drilling wells for primary production (five wells per section) to set up future waterflood schemes and finish construction of facilities and pipelines at Otter to enable the commencement of injection on an additional three operated waterflood schemes.
In accordance with Pinecrest adopting a restricted share incentive plan as approved at the June 5, 2013 Annual and Special meeting of the shareholders, the Board of Directors have approved a total grant of 5,026,500 incentive shares, of which 3,300,000 will be granted to directors and officers of the Company upon lifting of Pinecrest’s blackout period, anticipated to be August 20, 2013.
|(1)||“Discovered Oil Initially InPlace” or “DOIIP”means that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves and contingent resources. There is no certainty that it will be commercially viable to produce any portion of these resources.|
|(2)||All DOIIP other than cumulative production, reserves and contingent resources have been categorized as unrecoverable. Pursuant to the Assessment, as at January 31, 2012, 9.1 mmbbl of oil was classified as cumulative production and proved plus probable reserves.|
|(3)||“Contingent Oil Resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as distance from existing production, economic, legal, environmental, political, and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.|
|(4)||“Best Estimate” is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.|
|(5)||Please refer to the Company’s March 22, 2012 press release for additional details in respect of the Assessment.|
The information in this press 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”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, “would” and similar expressions. In particular, forward looking statements in this press release includes, but is not limited to: Pinecrest’s capital program and 2013 business objectives, Pinecrest’s 2013 budget, oil recovery rates, the effects of waterfloods on recovery factors, the potential success of waterfloods in the Slave Point area, decline rates and type curves for wells, production rates, effect of operations initiatives, timing for implementation of operating cost initiatives, exit rates for production and bank debt, downspacing opportunities, the quantity of reserves, and projections of market prices and costs. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Pinecrest’s control, including: the impact of general economic conditions; industry conditions; regulatory approvals and permits; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions, of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; 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. Pinecrest’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 Pinecrest will derive from them. Except as required by law, Pinecrest undertakes no obligation to publicly update or revise any forward-looking statements.
Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources or reserves described can be profitably produced in the future.
The Corporation uses the following terms for measurement within this press release that do not have a standardized prescribed meaning under GAAP and these measurements may differ from other companies and accordingly may not be comparable to measures used by other companies. The terms “funds from operations” and “operating netback” are not recognized measures under the applicable GAAP. Management of the Corporation believes that these terms are useful, in addition to profit and loss and cash flow from operating activities as defined by GAAP, for evaluating the Corporation’s operating performance and leverage. Funds from operations is expressed as cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures. Operating netback is a measure of operating margin used in capital allocation decisions. Pinecrest defines operating netback as average realized price per BOE, less royalties per BOE, less operating and transportation expenses per BOE, plus any realized gain or loss per BOE on financial instruments.
Certain information provided in this press release in relation to the results of waterflooding Slave Point reservoirs on lands in close proximity to the land in which the Company has an interest, is considered analogous information under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. Such information is based on publicly available information from governmental agencies and other industry producers and has been provided to give an indication of possible incremental recovery factors in the specified area. Other than comparing such information to the Company’s own limited results in the specified area, the Company has not independently confirmed the accuracy of this information. There is no certainty that such incremental recovery factors will be obtained of even if so obtained, whether such factors can be achieved on an economic basis.
Barrels of Oil Equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6MCF:1bbl 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.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
SOURCE Pinecrest Energy Inc.
For further information:
Pinecrest Energy Inc.
Suite 500, 255 – 5th Avenue S.W.
Calgary, Alberta T2P 3G6
Wade Becker, President and CEO
Dan Toews, V.P. Finance& CFO
Tel: (403) 817-2550 or
Fax: (403) 817-2599