Pinecrest Energy Inc. ("Pinecrest" or the "Company") announces that it has filed on SEDAR its unaudited financial statements and related Management's Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2013. The statements will be available for review at www.sedar.com or www.pinecrestenergy.com.
THIRD QUARTER 2013 HIGHLIGHTS
The following update highlights operational matters undertaken by Pinecrest during the three months ended September 30, 2013:
Completed field operations and injection well conversions on its third (Evi Project #3) and fourth (Red Earth Project #1) operated waterflood schemes, and commenced injection on both these schemes in late July. Subsequent to September 30, the Company initiated injection on three additional waterflood schemes in the Otter area, bringing the active waterflood count to eight, comprising more than one third of total corporate production;
Drilled 3 gross (3.0 net) wells achieving a 100% success rate:
Average production of 2,804 boe per day (97% light oil & NGLs). The Company's production for the quarter was adversely affected by a major facility turnaround (required 17 days of downtime; 307 boe per day lost production over the quarter) and by the conversion of seven producing oil wells to water injection (approximately 260 boe per day lost production over the quarter);
Top quartile field netback of $60.54 per boe;
Observed a production response at its Evi Project #3 (November oil production is up approximately 60% over June's production based upon field estimates); and
Average cost to drill, complete, and equip a well of $3.4 million. Pinecrest has been continuously refining its well design and has most recently achieved a cost savings of approximately $2.3 million per well as compared to the first half of 2012.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
September 30 Three months ended Nine months ended
2013 2012 2013 2012
FINANCIAL
Petroleum and natural gas sales 25,921 21,006 89,323 71,623
Funds flow from operations, before realized derivative
financial instrument gains or losses (1) 13,574 14,068 53,069 50,307
Funds flow from operations (1) 9,582 14,975 47,336 51,116
Per share - basic $0.04 $0.07 $0.22 $0.24
Per share - diluted $0.04 $0.06 $0.21 $0.21
Net income (loss) (843) 4,578 7,069 19,602
Per share - basic $0.00 $0.02 $0.03 $0.09
Per share - diluted $0.00 $0.02 $0.03 $0.08
Capital expenditures 23,886 56,979 79,761 132,480
Net debt and working capital deficit (2) (128,617) (51,489) (128,617) (51,489)
Common Shares Outstanding
Weighted average - basic 217,375 214,289 215,730 209,197
Weighted average - diluted 217,375 239,594 228,203 237,984
OPERATING
Number of days 92 92 273 274
Production
Crude oil (bbls/d) 2,674 2,730 3,457 3,002
Natural gas (mcf/d) 463 65 433 51
NGL (bbls/d) 53 7 43 7
Barrels of oil equivalent (boe/d-6:1) 2,804 2,748 3,572 3,018
Average realized price (3)
Crude oil ($/bbl) 103.90 83.50 93.66 86.91
Natural gas ($/mcf) 2.52 1.98 2.97 1.86
NGL ($/bbl) 51.54 35.09 48.91 52.10
Netback per boe ($)(1)
Petroleum and natural gas sales 100.46 83.09 91.59 86.61
Royalties (10.86) (6.67) (7.78) (6.67)
Production and transportation expenses (29.06) (15.68) (22.74) (14.80)
Field netback 60.54 60.74 61.07 65.14
Realized gain (loss) on derivative financial instruments (15.46) 3.59 (5.88) 0.98
Operating netback 45.08 64.33 55.19 66.12
Wells drilled
Gross 3.0 13.0 15.0 23.0
Net 3.0 12.8 14.3 22.5
Success rate (%) 100 100 100 100
(1) Non-GAAP measure
(2) Net debt and working capital if defined as current assets minus current liabilities, plus outstanding debt, excluding derivative financial instruments
(3) Before the effects of derivative financial instruments
WATERFLOOD UPDATE
During 2013, the Company has continued to focus its efforts on establishing a sustainable and predictable low decline light oil production base through the implementation of seven operated waterflood projects. During the quarter, seven wells producing approximately 260 barrels per day of oil were shut in and converted to water injectors for the Otter Projects #1, #2 and #3. These three projects are more than double the size of the initial four schemes and are forecast to provide a meaningful impact to the Company's production profile. Production response on these new projects is anticipated in Q1 2014. Pinecrest currently has over one third of its production being pressure maintained by waterflooding and as reservoir pressures rise and volumes increase as projected, this production base is expected to grow to approximately fifty percent of corporate production by early Q2 2014.
The Company continues to see encouraging results from the four previously announced operated waterflood schemes, Evi Project #2 (December 2012), Loon Project #1 (March 2013), Evi Project #3 (July 2013) and Red Earth Project #1 (July 2013). Response times and production increases for these schemes are within Company expectations. Wells in areas downspaced to eight wells per section have been the first to experience the effect of re-pressurization, resulting in quicker production increases than those spaced at four wells per section. The Company anticipates further gains in production rates from these and future Pinecrest operated schemes in the Greater Red Earth area. Pinecrest's active waterflood count is now comprised of eight projects and the Company has applied for an additional four schemes for implementation in 2014.
All 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. Excluding the August battery turnaround, offsetting producing wells in all 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.
The following chart shows the shallowing impact of pressure maintenance on the Company's waterflood production profile for the period September 2012 to October 2013. Additionally, the Company anticipates this production to increase as the balance of the 2013 waterfloods respond.
OPERATIONS UPDATE
Wet weather delayed the implementation of the Company's third quarter capital program and caused an increase in unscheduled downtime due to difficult field conditions. During the third quarter, the Company drilled three wells and completed two of these wells. The average cost to drill, complete and equip the wells drilled in the quarter was $3.4 million per well, a $2.3 million per well savings as compared to the first half of 2012.
Operating costs were also negatively impacted by the operating conditions (lease repair and road maintenance). Additionally, the initial start-up phase of the waterflood schemes caused an increase in operating costs. 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. Pinecrest has completed the field electrification at the Red Earth and Loon fields which will reduce costs. Injection water is now being delivered by pipeline to all but one of the Company's injection schemes, eliminating significant trucking costs. In addition, costs associated with emulsion trucking have been reduced as the majority of the wells have now been tied into central production facilities.
The Company expects that these initiatives and others currently being implemented will have a positive impact on lowering the Company's overall operating costs.
For the balance of 2013, Pinecrest is targeting total operating expenses (production and transportation costs) of approximately $23.00 per boe. The implementation of all of Pinecrest's operating cost initiatives will not be fully realized until Q1 2014.
Current production is approximately 2,650 boed, with approximately 350 boed shut in due to field conditions. For the balance of the year the company expects to invest minimal capital as it awaits the response of its waterfloods.
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% to 70%, which is typical for all tight oil reservoirs. With the licensing and implementation of the seven operated waterfloods, the Company has now transitioned 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 32%. It is expected that this overall decline rate will continue to abate as the full effect and benefit of the Company's waterflood initiatives occurs over the coming months.
This reduction in corporate decline rates combined with improving capital efficiencies and a focus on operating cost reductions, is projected to grow production while spending significantly less capital in the upcoming years. With the anticipated response of the remaining four operated 2013 waterfloods, the Company expects to generate cash flow in excess of capital requirements in 2014.
