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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| Nuloch Resources | TSXV:NLR.B | TSX Venture | Ordinary Share |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0.00 | - |
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NuLoch Resources Inc. (TSX VENTURE:NLR.A)(TSX VENTURE:NLR.B) retained AJM
Petroleum Consultants (AJM) to conduct the evaluation of the Company's petroleum
and natural gas reserves effective as at December 31, 2009. AJM is a qualified
reserves evaluator and their report (AJM Report), dated March 5, 2010 was
compiled pursuant to the guidelines of National Instrument 51-101.
This past year was one of transition where the Company has positioned itself to
take advantage of light oil resource plays in the Bakken and Three Forks Sanish
formations in the Williston Basin. A year ago, proved and probable reserves of
oil accounted for 9% of NuLoch's total reserves on a barrel of oil equivalent
basis; at December 31, 2009, oil has moved to 38% of the total. Proved
undeveloped (PUD) oil reserves have been assigned on some of the Company's 10%
working interest acreage in North Dakota. At Tableland, one Three Forks Sanish
horizontal well (1.0 net) that was drilled and completed in late 2009 has been
assigned proved light oil reserves of 130 Mbbl and proved plus probable reserves
of 180 Mbbl based on analogous wells located nearby in Divide County, North
Dakota. Given the early stage of development in Canada, there are no proved
undeveloped locations assigned to any of the Company's 34,200 net acres at
Tableland. Since year end, NuLoch has drilled two (1.4 net) offsetting Three
Forks Sanish wells that are awaiting completion and a third well (0.7 net)
located approximately six miles east that awaits completion in the Middle
Bakken.
Reserve extensions of 284 Mboe exceeded 2009 production of 210 Mboe by 1.3
times. In addition, the Company made three significant acquisitions of
production and undeveloped land in 2009 that added a further 1,179 Mboe and,
overall, reports a 49% increase in its proved and probable reserves volumes at
December 31, 2009 compared to a year ago. Net negative economic factors and
technical revisions to reserves recorded in prior years totalled 112 Mboe.
The three significant acquisitions completed during 2009 were:
- at Tableland, Saskatchewan, the working interest in existing lands was
increased by 16,800 net undeveloped acres;
- Wilderness Energy Corp. was acquired in an all-share transaction that doubled
NuLoch's interest in a prolific light oil field at Balsam, Alberta and added
considerable tax shelter including over $20 million in tax losses;
- in North Dakota, acquired 142 barrels per day of high-quality light oil
primarily from the Three Forks Sanish and Bakken formations and a 10% interest
in 220,000 largely contiguous net undeveloped acres.
Reserve value at December 31, 2009 has increased by 34% from a year ago despite
the lower natural gas price forecast used in the 2009 AJM Report. NuLoch's
undeveloped land position has increased from 32,400 net acres in 2008 to 94,800
net acres at December 31, 2009. Areas with Bakken and Three Forks Sanish
potential make up 56,200 of these net undeveloped acres. Subsequent to year end,
the Company further expanded its undeveloped lands in this play with an 8,500
net acre acquisition in Burke County, North Dakota.
In North Dakota, undeveloped locations (16 proven and 9 probable) with an
average working interest of 9.5% that offset existing Three Forks Sanish
producers have been identified and included in the AJM Report. On average, each
of the 16 PUD locations has been assigned gross proved oil reserves of 122 Mboe
and 51 Mboe of probable additional reserves. Each of the 9 probable locations
has been assigned an average of 168 Mboe probable additional reserves.
The Company's reserve life index on a proved plus probable basis is 13.5 years.
NuLoch's reserves of petroleum and natural gas and associated future net
revenues as at December 31, 2009 are presented below.
Company Gross Future Net
Reserves(1)(2) Revenue(1)(3)
----------------------- -------------------------------- -----------------
Light & Nat-
Medium Heavy ural ($ millions)
Oil Oil Gas NGL Total Discount Rate
Reserves Category Mbbl Mbbl MMcf Mbbl Mboe 0% 10% 15%
----- ----- ------ ---- ------ ----- ----- -----
CANADA
----------------------- -------------------------------- -----------------
Proved
Developed Producing 455 16 3,475 13 1,063 27.5 18.9 16.4
Developed Non-producing - - 722 5 125 1.6 1.3 1.2
Undeveloped - - 4,085 2 683 7.4 1.7 0.4
----- ----- ------ ---- ------ ----- ----- -----
Total Proved 455 16 8,282 20 1,871 36.5 21.9 18.0
Probable 179 7 4,301 9 912 29.5 10.0 6.9
----- ----- ------ ---- ------ ----- ----- -----
Total Proved and Probable 634 23 12,583 29 2,783 66.0 31.9 24.9
----- ----- ------ ---- ------ ----- ----- -----
----- ----- ------ ---- ------ ----- ----- -----
UNITED STATES
----------------------- -------------------------------- -----------------
Proved
Developed Producing 177 - 25 - 181 8.9 5.5 4.7
Developed Non-producing - - - - - - - -
Undeveloped 174 - - - 174 2.8 (0.7) (1.5)
----- ----- ------ ---- ------ ----- ----- -----
Total Proved 351 - 25 - 355 11.7 4.8 3.2
Probable 314 - 20 - 317 17.1 3.4 1.6
----- ----- ------ ---- ------ ----- ----- -----
Total Proved and Probable 665 - 45 - 672 28.8 8.2 4.8
----- ----- ------ ---- ------ ----- ----- -----
----- ----- ------ ---- ------ ----- ----- -----
TOTAL
----------------------- -------------------------------- -----------------
Proved
Developed Producing 632 16 3,500 13 1,244 36.3 24.4 21.1
Developed Non-producing - - 722 5 125 1.6 1.3 1.2
Undeveloped 174 - 4,085 2 857 10.2 1.0 (1.1)
----- ----- ------ ---- ------ ----- ----- -----
Total Proved 806 16 8,307 20 2,226 48.1 26.7 21.2
Probable 492 7 4,321 9 1,229 46.7 13.4 8.5
----- ----- ------ ---- ------ ----- ----- -----
Total Proved and Probable 1,298 23 12,628 29 3,455 94.8 40.1 29.7
----- ----- ------ ---- ------ ----- ----- -----
----- ----- ------ ---- ------ ----- ----- -----
(1) Columns and rows may not add due to rounding
(2) Six mcf of natural gas is considered equivalent to 1 barrel of oil. (see
Advisories)
(3) Future net revenues do not represent fair market value
The following tables summarize the changes in the Company's working interest
reserves since December 31, 2008 based on forecast prices and costs. The change
includes an acquisition in the United States consisting of 359 Mboe of proved
light oil reserves and 673 Mboe on a proved and probable basis.
Summary Analysis of Changes in Reserves (Company Working Interest)(1)
----------------------------------------------------------------------------
($ millions)
Future Net
(Mboe) Revenue
--------------------------- Before Tax
Proved Probable Total 10% DCF
-------- -------- ------- ----------
December 31, 2008 1,571 743 2,314 $29.9
Extensions 197 87 284
Technical revisions (18) (53) (71)
Economic factors (28) (13) (41)
Acquisitions 714 465 1,179
Production (210) - (210)
-------- -------- -------- ----------
December 31, 2009 2,226 1,229 3,455 $40.1
-------- -------- -------- ----------
-------- -------- -------- ----------
Percentage changes
Extensions 13 % 12 % 12 %
Technical revisions (1)% (7)% (3)%
Economic factors (2)% (2)% (2)%
Acquisitions 45 % 63 % 51 %
Production (13)% - (9)%
-------- -------- -------- ---------
Overall change 42 % 65 % 49 % 34 %
-------- -------- -------- ----------
-------- -------- -------- ----------
(1) Columns and rows may not add due to rounding
Reserve Reconciliation (Company Working Interest)(1)
----------------------------------------------------------------------------
Light &
Medium Heavy Natural
Oil Oil Gas NGL Total
(Mbbl) (Mbbl) (MMcf) (Mbbl) (Mboe)
------- ------- ------- ------- -------
Proved
December 31, 2008 132 27 8,370 17 1,571
Extensions 129 - 405 - 197
Technical revisions 56 - (431) (1) (18)
Economic factors - - (168) - (28)
Acquisitions 561 - 868 8 714
Production (72) (11) (737) (4) (210)
------- ------- ------- ------- -------
December 31, 2009 806 16 8,307 20 2,226
Probable
December 31, 2008 47 7 4,106 5 743
Extensions 53 - 203 - 87
Technical revisions 6 1 (364) - (53)
Economic factors - (1) (69) - (13)
Acquisitions 387 - 446 4 465
Production - - - - -
------- ------- ------- ------- -------
December 31, 2009 492 7 4,322 9 1,229
Proved and probable
December 31, 2008 178 34 12,476 22 2,314
Extensions 182 - 608 - 284
Technical revisions 61 1 (795) (1) (71)
Economic factors - (1) (237) - (41)
Acquisitions 948 - 1,314 12 1,179
Production (72) (11) (737) (4) (210)
------- ------- ------- ------- -------
December 31, 2009 1,298 23 12,629 29 3,455
------- ------- ------- ------- -------
------- ------- ------- ------- -------
(1) Columns and rows may not add due to rounding
Future Development Costs
The following table sets forth the future development costs which have been
deducted in determining future net revenue attributable to the reserves
categories noted below.
Forecast Prices and Costs
($ millions)
------------------------------------------
Canada United States
-------------------- -------------------
Proved Proved
and and
Year Proved Probable Proved Probable
------------------------------ -------- --------- -------- --------
2010 2.4 2.4 6.8 10.8
2011 8.2 8.2 - -
2012 - - - -
2013 - - - -
2014 - - - -
Remaining - 0.2 - -
------------------------------ -------- --------- ------- --------
Total (undiscounted) 10.6 10.8 6.8 10.8
-------- --------- ------- --------
-------- --------- ------- --------
Virtually all of the 2011 expenditures in Canada relate to development of the
Company's shallow natural gas prospect at Enchant, Alberta. NuLoch will assess
the merits of pursuing that development in 2011 in the context of natural gas
markets at that time.
Reserve Life Index
---------------------------------------------------------------------------
Production (Q4 2009 average boe/d) 700
Proved reserves (Mboe) 2,226
Proved reserve life index (years) 8.7
Proved plus probable reserves (Mboe) 3,455
Proved plus probable reserve life index (years) 13.5
Future prices used in the forecast of net revenue are based on those
estimated by AJM as at December 31, 2009. The first five years of forecast
prices for certain benchmarks are summarized below:
Five-Year Forecast of Future Prices
----------------------------------------------------------------------------
Oil Oil Natural gas
WTI Edmonton AECO average
Year ($US/bbl) ($CDN/bbl) ($CDN/Mcf)
---- --------- ---------- --------------
2010 75.00 77.55 5.80
2011 81.60 84.45 6.70
2012 85.85 88.90 7.05
2013 90.20 93.45 7.45
2014 97.40 101.05 7.55
Wells Drilled in 2009
----------------------------------------------------------------------------
The Company drilled 11 (3.7 net) wells during 2009. Three (0.3 net) of these
wells were in progress in North Dakota when the Company closed its Divide
County acquisition on October 26, 2009.
Natural Success
Oil gas Dry Total ratio
------- ------- ------- ------- -------
Gross 9 1 1 11
Net 2.5 0.2 1.0 3.7 73%
Finding, Development and Acquisition (FD&A) Costs
FD&A costs are derived by dividing all costs incurred in exploratory,
development and acquisition activities in a period by the proved and proved plus
probable reserves added in that period. These FD&A costs are further adjusted to
include any future development activity estimated to be required to place the
reported reserves on production.
The Company has not yet released its audited financial statements for the year
ended December 31, 2009. Additions to property and equipment in 2009, including
acquisitions, are estimated at $22,000,000 but are subject to audit and may be
revised as necessary.
FD&A Costs
For the three years ended December 31, 2009
(Millions)
----------------------------------------------------------------------------
3 Year
Average
2007 2008 2009 2009
----- ------ ------ ------
F&D costs (excluding acquisitions) per boe
- Proved $ 25.02 $146.64 $49.28 $53.65
- Proved plus probable $ 13.75 (i) $44.43 $49.47
FD&A cost (including acquisitions) per boe
- Proved $ 25.02 $146.64 $36.25 $42.49
- Proved plus probable $ 13.75 (i) $26.35 $32.65
(i) 2008 F&D costs not applicable due to negative technical revisions.
ADVISORIES
Reserves Disclosure
Reserves information presented relates to NuLoch's working interest share of
reserves and present values as at December 31, 2009. The reserves are reported
using AJM's forecast prices and costs. Complete reserves disclosure will be
included in the Company's Form 51-101 filing for the year ended December 31,
2009. The reserves definitions used in this document are consistent with the
Company's last NI 51-101 annual reserves filing posted on SEDAR on April 14,
2009.
Use of Barrels of Oil Equivalent (boe)
Disclosure provided herein in respect of boe units may be misleading,
particularly if used in isolation. A boe conversion ratio of 6 mcf of natural
gas to 1 bbl of crude oil is based on an energy equivalency conversion method
primarily applicable at the burner tip and may not represent a value equivalency
at the wellhead.
Use of Estimates
The net present value of future net revenue attributable to the Company's
reserves is stated without provision for interest costs and general and
administrative costs, but after providing for estimated royalties, production
costs, development costs, other income, future capital expenditures, and well
abandonment costs for only those wells assigned reserves by AJM. The estimates
of reserves and future net revenue for individual properties may not reflect the
same confidence level as estimates of reserves and future net revenue for all
properties, due to effects of aggregation. Actual recoveries may be greater than
or less than the estimates provided herein and there is no guarantee that the
estimated reserves will be recovered. It should not be assumed that the values
of future net revenue attributable to the Company's reserves represent the fair
market value of those reserves.
Calculation of Finding and Development Costs
Finding costs per boe of reserves added are a rough measure of the average per
unit costs of finding and developing petroleum and natural gas reserves.
The aggregate of the exploration and development costs incurred in the most
recent financial year and the change during that year in estimated future
development costs generally will not reflect total finding and development costs
related to reserve additions for that year.
Forward-Looking Statements
Certain statements in this document or incorporated herein by reference
constitute "forward-looking statements". These forward-looking statements can
generally be identified as such because of the context of the statements,
including words indicating that the Company "believes", "anticipates",
"expects", "plans" or words of a similar nature. Such forward-looking statements
involve known and unknown risks, uncertainties and other factors which may cause
the actual results, performance or achievements of the Company, or industry
results, to be materially different from any future results, performance or
achievements expressed or implied by such forward-looking statements. Such
factors include, among others, the following: general economic and business
conditions which will, among other things, impact demand for and market prices
of the Company's products; industry capacity; the ability of the Company to
implement its business strategy, including exploration and development
activities; the ability of the Company to complete its capital programs;
successful negotiations with bankers and other third parties; the success of
exploration and development activities; production levels; government
regulations and the expenditures required to comply with them (especially safety
and environmental laws and regulations); asset retirement obligations; and other
circumstances affecting revenues and expenses.
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