Great Plains Exploration Highlights Key Accomplishments for 2008
Great Plains Exploration has announced its financial and operational results for the three months and year ended December 31, 2008.
Key Accomplishments for 2008 and early 2009 were:
- Discovery of three light oil pools at Pembina/Crossfire and two gas pools at Northeast British Columbia (NEBC). These discoveries in aggregate, along with temporarily shut-in wells, represent approximately 1,200 to 1,500 BOE/d (80% oil) of additional productive capacity the majority of which Great Plains management expects to bring on-stream in 2009.
- Increase in Q4 2008 production by 83% (1,975 BOE/d; 40% oil) over Q4 2007, while year-over-year average production increased 31%.
- Expansion of company-operated production from 25% to approximately 70%.
- Proved plus probable reserve growth of 43% over 2007, not including recently announced discoveries at Crossfire, Gunnel and Helmet.
- Acquisition of RedStar Oil & Gas (RedStar) which contributed critical mass and provided an operated foothold in NEBC.
- Consolidation of the Company's position in NEBC by acquiring production, facilities at Klua and a 300,000 acre exploration block
- at Greater Sierra for $11 million.
Over the past several months, Great Plains management has scaled back its capital programs in response to the current business environment, while attempting to maintain momentum on those projects which are key to the Company's long-term business plan. We have made positive progress in our core operating areas and will continue to do so through 2009.
The operational reserves and financial highlights for 2008 are as follows:
- Produced an average of 1,552 BOE/d for the year, which reflects the RedStar acquisition in May that added approximately 600 BOE/d on a weighted average basis. For the fourth quarter, average production increased to 1,975 BOE/d from 1,684 BOE/d for the third quarter, with the increase mainly due to the commencement of oil production from the 9-1 discovery well at Pembina. Current production is approximately 1,600 BOE/d (33% oil; 67% gas) which reflects the temporary shut-in of 9-1 (400 BOE/d) and Klua A-17-G (100 BOE/d).
- Invested a total of $23.0 million (excluding acquisitions, dispositions and capitalized G&A) on the Company's capital projects, of which $13.3 million was spent on drilling and completing, tie-in or abandoning 13 wells (9.06 net) comprising of 4 (2.18 net) oil wells, 4 (3.08 net) gas wells and 5 (3.8 net) wells which were abandoned. The balance of expenditures were for land, seismic and facilities construction.
- Including RedStar and other acquisitions, invested a total of $47.7 million for the addition of 2.86 MMBOE of reserves, representing an FD&A cost of $16.69 per BOE. A further $7.1 million was invested in ongoing exploration projects for which no reserves were assigned at year-end, as these assets are to be developed in 2009 and 2010.
- Disposed of non-core assets comprising 40 BOE/d of production and 131,000 BOE of reserves for total proceeds of $2.8 million.
- Total proved reserves 3.9 MMBOE, total proved plus probable reserves of 5.7 MMBOE (comprised of 38% oil and NGLs and 62% natural gas) compared to proved reserves of 2.34 MMBOE and proved plus probable reserves of 4.01 MMBOE at the prior year-end.
- Net present value of total proved plus probable reserves discounted at 10% before income taxes of $94.2 million based on price deck with 2009 forecast of U.S. $57.50 WTI and CDN $7.58 AECO spot pricing.
- Year-end net asset value (NAV) of $1.03 per share (based on P+P, PV10), with land independently valued at $23.7 million, excluding seismic and including year-end net debt of $ 23.5 million.
2008 Year In Review
As challenging as 2007 was for junior producers, few could have imagined that 2008 would find our sector in an even tougher position. The combination of royalty trust taxation changes, weak gas prices and the New Royalty Framework for Alberta resulted in severe challenges in our business environment which were further exacerbated by the collapse of international credit markets and significant decreases in global demand for commodities.
Investor interest in junior energy players which had begun to rebound in the second quarter of 2008 completely disappeared and the traditional sources of equity capital for our business dried up. As a consequence of these events, Great Plains chose to take a very cautious approach to capital spending for the fall and winter and focused on a limited number of projects which match the Company's long-term objectives while managing the realities of the current environment. We concentrated on integrating those assets which we acquired while consolidating our internal project inventory. Pursuant to our long-standing corporate strategy, several corporate merger and acquisition opportunities were evaluated throughout the year and we continue to examine prospects for strategic growth.
The RedStar acquisition completed in May 2008 was a significant move for Great Plains and was specifically designed to improve our critical mass, strengthen our balance sheet and provide a hedge against the New Alberta Royalty Framework. This transaction dramatically increased our proportion of company-operated production and gave Great Plains a good opportunity to step into an exploration area with a land position, excellent seismic coverage and solid prospect leads. While well payouts reduced our share of production from the RedStar assets, we are generally satisfied with the early outcomes from this transaction and Great Plains expects improved performance from increasing familiarity with the operations of these properties.
The RedStar deal in turn generated an opportunity to consolidate and build our position in NEBC through the acquisition of assets at Klua. In addition, we obtained exclusive access to a large exploration block in the Greater Sierra area encompassing the majority of the RedStar assets. The Klua assets included approximately 340 BOE/d of production from a reserve base estimated at approximately 500,000 proved plus probable BOE. Facilities included 55 km of gathering lines and an operated sour gas plant with current capacity of 10 MMcf/d which can be expanded to 20 MMcf/d. This underutilized capability in both the plant and gathering system offers capacity for re-completion opportunities as well as new drilling and future shale gas development. The Great Plains technical team believes that there is exploration potential to find prospects from 3 to 20 bcf in size and drilled a Keg River prospect this past winter, which is currently being evaluated for a
side-track drilling operation in the summer or fall of 2009.
Pursuant to agreements governing the Greater Sierra exploration block, Great Plains agreed to spend $5 million on exploration in the fall of 2008 and was granted the right to explore approximately 300,000 acres for a two-year period which may be extended for another two years by further work commitments. Great Plains' obligations in NEBC for 2008 and 2009 have been fulfilled, with one well required in the 2009/2010 winter drilling season. Our primary technical focus in this area has been the Debolt and Bluesky formations which we evaluate using an extensive inventory of 2D and 3D seismic data. Target well depths are typically 600 to 700 metres which can be drilled at an approximate cost of $400,000 to $450,000 per well depending on the size of the program. Debolt wells in this area average 2 to 2.5 bcf of reserves per well with average production rates of 2.1 MMcf/d. Bluesky wells are somewhat less prolific but still average 1.25 to 1.5 bcf per well with average production at 750 Mcf/d. Based on drilling success at Gunnel and Helmet, as well as in-depth geological and geophysical work on other exploration leads, the Great Plains team has identified 10 firm locations with 18 other targets currently being defined. While the current price of natural gas dictates a cautious approach in NEBC, we remain confident in the economic viability of this area based on decreasing service costs and forecast gas prices. Economic analysis of our projects indicates that depending upon the individual location
and its risked chance of success, gas prices of approximately $2.50 to $3.60 per Mcf are required to generate a positive net present value, using a 10% discount rate.
Great Plains' commitment to investing in a long-term business plan is best illustrated by reviewing our progress over the past two years at Pembina. Early stage investment has yielded positive outcomes in the form of three successful Nisku wells over the past year, three wells planned for the balance of 2009, plus the 10 additional locations which remain in inventory. While the slow pace of development in Pembina is always frustrating, these light oil prospects continue to demonstrate superior economics with the potential for material increases in production. The Company's main drive for the remainder of the year will be to capitalize on the exploration success to-date and bring these significant amounts of behind pipe oil production on-stream in 2009. Of the three Nisku locations scheduled for 2009 drilling, two are already licensed, with drilling operations expected to commence in late June or early July.
Based on general area statistics and our previous Nisku exploration successes, Great Plains continues to target 1.0 MMbbls per well with average productivity of 1,000 BOPD. Our licensed location at Tomahawk 1-16-51-6 W5M has already been drilled to the base of the Wabamun formation and will only require a relatively inexpensive deepening operation to test for Nisku oil potential. The licensed location at 9-17-51-6 W5M will be a step-out well based on the success of 1-16 so the amount of risk capital required is very modest both in absolute terms and relative to the potential size of the prize.
A 1-16 discovery would provide additional upside through the addition of critical mass which would allow for pipeline construction to bring on shut-in oil volumes from previous discoveries at 15-7-51-6 W5M and 8-35-50-7 W5M. All the foregoing activity provides Great Plains with good opportunities for growth in light oil production from an optimal combination of tie-in projects and proven exploration ideas.
Lacking reasonable assurance as to when gas prices or equity markets will recover, Great Plains management will continue to preserve cash flow and focus on projects that are expected to provide either near-term production additions or significant impact to our underlying value. Capital expenditure for the balance of 2009 will be primarily directed towards previously mentioned drilling locations as well as tieing-in production at Pembina/Crossfire. Light oil from the Pembina/Crossfire area accounts for roughly 80% of the estimated 1,200 to 1,500 BOE/d of behind pipe volumes while three wells in NEBC account for the remaining balance. Great Plains is still in an excellent position to offer the possibility of significant production growth which will be primarily focused on light oil.
While management believes that oil prices have recovered (for the moment) to a reasonably stable level, we are cautiously optimistic that we may see some additional strength in oil in 2009 albeit somewhat offset by a weaker U.S. dollar. On the gas side, there is likely further short-term downside but there are now early indications that supply response to low drilling activity may provide an earlier and stronger up tick in gas prices. In the meantime, we are budgeting with an expectation of U.S. $50 WTI oil and CDN $5.00 AECO gas, but will continue to review our capital activity in the context of new price scenarios and our hedging program.
With an expectation that our primary credit facility of $38 million will be reduced, we have planned for such a contingency and pursuant to our budget plan we expect to keep our drawings below $26 million. Given the strength of the Company's hedge positions and our ability to maintain a reasonable credit facility with our lenders, we expect to be able to fund our projects from cash flow and debt as required.
The Great Plains team has continued to put forth an exemplary effort in the face of some very challenging times and I wish to thank them for their perseverance. Likewise, your Directors have continued to provide top notch guidance throughout the past year and I consider myself fortunate to have access to people of this calibre. Lastly, I am grateful for the continued support from our core shareholders and I appreciate the ongoing dialogue with those of you who have taken the time to meet, write or call with constructive comments.