e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark one)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31, 2008
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission file number
001-33801
APPROACH RESOURCES
INC.
(Exact name of registrant as
specified in its charter)
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Delaware
(State or other jurisdiction
of
incorporation or organization)
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51-0424817
(I.R.S. employer
identification number)
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One Ridgmar Centre
6500 W. Freeway, Suite 800
Fort Worth, Texas
(Address of principal
executive office)
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76116
(Zip code)
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(817) 989-9000
(Registrants telephone
number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
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Title of each class
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Name of each exchange on which registered
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Common stock, par value $0.01 per share
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NASDAQ Global Select Market
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act.
Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
is not contained herein and will not be contained, to the best
of Registrants knowledge, in definitive proxy or
information statements incorporated by reference in
Part III of this
Form 10-K
or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large accelerated
filer o
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Non-accelerated
filer o
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(Do not check if a smaller reporting company)
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Accelerated
filer þ
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Smaller reporting
company o
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Indicate by check mark whether the registrant is a shell company
(as defined in Exchange Act
Rule 12b-2). Yes o No þ
The aggregate market value of the voting and non-voting common
equity held by non-affiliates (excluding voting shares held by
officers and directors) as of June 30, 2008 (based on the
closing price on the Nasdaq Global Market on such date) was
$273.4 million. The number of shares of the
registrants common stock, par value $0.01, outstanding as
of March 6, 2009 was 20,731,429.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrants proxy statement for its 2009
annual meeting of stockholders are incorporated by reference in
Part III, Items 10-14
of this report.
APPROACH
RESOURCES INC.
Unless the context otherwise indicates, all references in
this report to Approach, the Company,
we, us or our are to
Approach Resources Inc. and its subsidiaries. Unless otherwise
noted, all information in this report relating to oil and
natural gas reserves and the estimated future net cash flows
attributable to those reserves are based on estimates and are
net to our interest. If you are not familiar with the oil and
gas terms used in this report, please refer to the definitions
of these terms under the caption Glossary at the end
of Item 15 of this report.
TABLE OF
CONTENTS
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Cautionary
Statement Regarding Forward-Looking Statements
Various statements in this report, including those that express
a belief, expectation or intention, as well as those that are
not statements of historical fact, are forward-looking
statements. The forward-looking statements may include
projections and estimates concerning the timing and success of
specific projects, typical well economics and our future
reserves, production, revenues, income and capital spending.
When we use the words believe, intend,
expect, may, should,
anticipate, could, estimate,
plan, predict, project or
their negatives, other similar expressions or the statements
that include those words, it usually is a forward-looking
statement.
The forward-looking statements contained in this report are
largely based on our expectations, which reflect estimates and
assumptions made by our management. These estimates and
assumptions reflect our best judgment based on currently known
market conditions and other factors. Although we believe such
estimates and assumptions to be reasonable, they are inherently
uncertain and involve a number of risks and uncertainties that
are beyond our control. In addition, managements
assumptions about future events may prove to be inaccurate. We
caution all readers that the forward-looking statements
contained in this report are not guarantees of future
performance, and we cannot assure any reader that such
statements will be realized or the forward-looking events and
circumstances will occur. Actual results may differ materially
from those anticipated or implied in the forward-looking
statements due to the factors listed in the Risk
Factors section and elsewhere in this report. All
forward-looking statements speak only as of the date of this
report. We do not intend to publicly update or revise any
forward-looking statements as a result of new information,
future events or otherwise. These cautionary statements qualify
all forward-looking statements attributable to us, or persons
acting on our behalf. The risks, contingencies and uncertainties
relate to, among other matters, the following:
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global economic and financial market conditions,
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our business strategy,
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estimated quantities of oil and gas reserves,
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uncertainty of commodity prices in oil and gas,
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continued disruption of credit and capital markets,
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our financial position,
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our cash flow and liquidity,
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replacing our oil and gas reserves,
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our inability to retain and attract key personnel,
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uncertainty regarding our future operating results,
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uncertainties in exploring for and producing oil and gas,
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high costs, shortages, delivery delays or unavailability of
drilling rigs, equipment, labor or other services,
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disruptions to, capacity constraints in or other limitations on
the pipeline systems which deliver our gas and other processing
and transportation considerations,
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our inability to obtain additional financing necessary to fund
our operations and capital expenditures and to meet our other
obligations,
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competition in the oil and gas industry,
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marketing of oil, gas and natural gas liquids,
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exploitation or property acquisitions,
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technology,
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the effects of government regulation and permitting and other
legal requirements,
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plans, objectives, expectations and intentions contained in this
report that are not historical, and
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other factors discussed under Item 1A. Risk
Factors in this report.
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iii
PART I
General
We are an independent energy company engaged in the exploration,
development, production and acquisition of unconventional
natural gas and oil properties in the United States and British
Columbia. We focus on natural gas and oil reserves in tight
sands and shale and have assembled leasehold interests
aggregating approximately 300,334 gross (199,818 net) acres
as of December 31, 2008. Our management team has a proven
track record of finding and exploiting unconventional reservoirs
through advanced completion, fracturing and drilling techniques.
As the operator of over 90% of our production and proved
reserves, we have a high degree of control over capital
expenditures and other operating matters.
We currently operate or have interests in the following areas:
West Texas
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Ozona Northeast (Wolfcamp, Canyon Sands, Strawn and Ellenburger)
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Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)
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East Texas
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North Bald Prairie (Cotton Valley Sands, Bossier and Cotton
Valley Lime)
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Southwest Kentucky
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Boomerang (New Albany Shale)
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Northeast British Columbia
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Montney tight gas and Doig Shale
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Northern New Mexico
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El Vado East (Mancos Shale)
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At December 31, 2008, we owned working interests in 445
producing oil and gas wells, had estimated proved reserves of
approximately 211.1 Bcfe and were producing
28.0 MMcfe/d (based on production for the month of December
2008). Our average daily net production in 2009 (through
February) was 26.5 MMcfe/d.
As of December 31, 2008, all of our proved reserves and
production were located in Ozona Northeast and Cinco Terry in
West Texas and in North Bald Prairie in East Texas. At year end
2008, our proved reserves were 82% natural gas, 48% proved
developed and had a reserve life index of over 20 years
(based on 2008 production of 8,755 MMcfe). In addition to
our producing wells, we have identified 1,205 total drilling
locations in Ozona Northeast, Cinco Terry and North Bald Prairie
at December 31, 2008, of which 312 are proved.
The standardized measure of discounted future net cash flows of
our proved reserves at December 31, 2008 was
$142.6 million, and our
PV-10 was
$221.1 million.
PV-10 is a
non-GAAP financial measure as defined by the Securities and
Exchange Commission, or the SEC, and generally differs from the
standardized measure of discounted future net cash flows, the
most directly comparable GAAP financial measure, because
PV-10 does
not include the effects of income taxes on future net revenues.
See Items 1. and 2., Business and
Properties Reconciliation of non-GAAP financial
measure
(PV-10)
for our definition of
PV-10 and a
reconciliation of
PV-10 to the
standardized measure of discounted future net cash flows.
In December 2008, in response to a decline in oil, gas and NGL
prices and uncertain market conditions, we announced that we
were reducing our capital expenditure budget to an estimated
$43.8 million in 2009, compared to $100.1 million of
actual capital expenditures in 2008 (including
$10.3 million in exploration and development costs related
to the acquisition of the deep rights in Ozona Northeast in July
2008). We have reduced the number of our operating rigs from
five in June 2008 to two at February 28, 2009. We intend to
fund 2009 capital expenditures (excluding any acquisitions)
with internally generated cash flow, with any excess cash flow
applied towards debt, working capital or strategic acquisitions.
We will continue to monitor commodity prices and operating
expenses to determine any further adjustments to the capital
budget and,
1
unless commodity prices strengthen, we will materially reduce
our 2009 capital expenditures and number of operated rigs from
the $43.8 million capital budget announced in December 2008.
Approach was incorporated in 2002. Our common stock began
trading on the NASDAQ Global Market in the United States under
the symbol AREX on November 8, 2007. In
December 2008, our common stock became listed on the NASDAQ
Global Select Market. Our principal executive offices are
located at One Ridgmar Centre, 6500 W. Freeway,
Suite 800, Fort Worth, Texas 76116. Our telephone
number is
(817) 989-9000.
Strategy
Our objective is to build long-term stockholder value through
growth in reserves and production in a cost-efficient manner. We
intend to accomplish this objective by using a balanced program
of (1) developing our core properties, (2) increasing
our acreage, reserves and production through joint ventures,
(3) completing strategic acquisitions, (4) maintaining
financial flexibility, and (5) exploring and exploiting our
undeveloped properties. The following are key elements of our
strategy:
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Continue to develop our core properties. We
intend to develop further the significant remaining potential of
our Ozona Northeast, Cinco Terry and North Bald Prairie
properties, where we have identified 1,205 drilling
locations. We believe we have the technical expertise and
operational experience to maximize the value of these
properties. From 2004 through 2008, we drilled over
377 wells in our Ozona Northeast and Cinco Terry fields in
West Texas, making us the second most active driller in the
Canyon Sands in West Texas during that time period.
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Increase our land holdings, reserves and production through
farm-ins and drilling ventures. Our participation
in farm-ins and a joint drilling venture has allowed us to grow
our acreage position and reserves in Ozona Northeast
(49,169 gross and 44,044 net acres and 144.4 Bcfe
of proved reserves), North Bald Prairie (9,301 gross and
4,361 net acres and 20.8 Bcfe of proved reserves) and
Northeast British Columbia (31,231 gross and 7,395 net
acres). Farm-ins, joint drilling or drill-to-earn
ventures and similar agreements can allow us to develop
strategic, unconventional gas and oil properties for a
substantially lower initial investment than acquiring the
property outright.
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Acquire strategic assets. We continually
review opportunities to acquire producing properties,
undeveloped acreage and drilling prospects. We focus
particularly on opportunities where we believe our reservoir
management and operational expertise in unconventional gas and
oil properties will enhance value and performance. We remain
focused on unconventional resource opportunities, but also look
at conventional opportunities based on individual project
economics. In 2008, we expanded our Cinco Terry net acreage
position to 45,288 gross (19,466 net) acres, from
21,900 gross (9,507 net) acres in 2007. In addition, in
July 2008, we acquired an additional 95% working interest in all
depths below the top of the Strawn formation, 7.7 Bcfe of
proved reserves, compression facilities and rights to
approximately 75 miles of gathering lines in Ozona
Northeast.
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Operate our properties as a low cost
producer. We seek to minimize our operating costs
by concentrating our assets within geographic areas where we can
consolidate operating control and thus create operating
efficiencies. We operate over 90% of our production and proved
reserves and plan to continue to operate a substantial portion
of our producing properties in the future. Operating control
allows us to better manage timing and risk as well as the cost
of exploration and development, drilling and ongoing operations.
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Maintain financial flexibility. At
December 31, 2008, we had $43.5 million in long-term
debt outstanding under our revolving credit facility, providing
us with significant financial flexibility to pursue our business
strategy. At February 28, 2009, we had $47.4 million
in long-term debt outstanding under our credit facility. As
discussed above, in response to a decline in commodity prices
and current market conditions we have reduced our expected
capital expenditure budget for 2009. We will further reduce
capital expenditures for 2009 unless commodity prices
strengthen. We intend to fund our 2009 capital expenditure
budget with internally generated cash flow, with any excess cash
flow applied towards debt, working capital or strategic
acquisitions.
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2
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Exploit our undeveloped gas and oil
opportunities. We have an estimated
257,491 gross acres of undeveloped tight gas and shale gas
and oil inventory to explore and produce. On a long-term basis,
we believe we can add proved reserves and production from these
properties through advanced technologies, including horizontal
drilling and advanced fracing and completion techniques.
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Oil and
gas properties and operations
West
Texas
Ozona
Northeast (Wolfcamp, Canyon Sands, Strawn and
Ellenburger)
The Ozona Northeast field in Crockett and Schleicher counties,
Texas, is our largest operating area on the basis of proved
reserves and production. In 2004, we began operations in the
field through a farmout arrangement and have increased our total
acreage position to 49,169 gross (44,044 net) acres.
Beginning with our first well in February 2004, through
December 31, 2008, we have drilled 311 successful wells out
of 332 total wells drilled, for a 94% success rate. As of
December 31, 2008, we had estimated proved reserves of
144.4 Bcfe from Ozona Northeast.
On July 1, 2008, we acquired an additional 95% working
interest in all depths below the top of the Strawn formation,
compression facilities and rights to approximately 75 miles
of gathering lines in Ozona Northeast. As a result of the
acquisition, we now own substantially all working interests in
all depths of the subsurface in Ozona Northeast and have a net
revenue interest of approximately 80% in Ozona Northeast.
Including the 75 miles of gathering lines acquired on
July 1, 2008, we own and operate approximately
150 miles of gas gathering lines in the area.
Average daily production in 2008 from Ozona Northeast was
16.4 MMcfe/d (net), or a total of 5,975 MMcfe. Average
daily production in 2009 (through February) from Ozona Northeast
was 16.0 MMcfe/d (net). We have identified 660 additional
drilling locations in Ozona Northeast as of December 31,
2008, of which 192 are proved.
Cinco
Terry (Wolfcamp, Canyon Sands and Ellenburger)
Since late 2005, we have leased and acquired options to lease
45,288 gross (19,466 net) acres in our Cinco Terry project,
two miles northwest of the Ozona Northeast border, to explore
the Wolfcamp, Canyon and Ellenburger formations. As of
December 31, 2008, we had estimated proved reserves of
45.9 Bcfe in Cinco Terry, compared to 18.3 Bcfe of
estimated proved reserves at December 31, 2007. We have
approximately a 52% working interest and 39% net revenue
interest in our Cinco Terry project. Average daily production in
2008 from Cinco Terry was 6.4 MMcfe/d (net), or a total of
2,333 MMcfe. Average daily production in 2009 (through
February) from Cinco Terry was 9.3 MMcfe/d (net). We have
identified 456 additional drilling locations in our Cinco Terry
acreage as of December 31, 2008, of which 89 are proved. We
own and operate seven miles of gas gathering lines in the area.
East
Texas
North
Bald Prairie (Cotton Valley Sands, Bossier and Cotton Valley
Lime)
In July 2007, we entered into a joint drilling venture with
EnCana Oil & Gas (USA) Inc. in the East Texas Cotton
Valley/Bossier trend. As part of the joint venture, we agreed to
drill up to five wells at our cost to earn a 50% working
interest in approximately 9,301 gross (4,361 net) acres. We
began drilling operations on the initial North Bald Prairie well
in August 2007. As of December 31, 2008, we had drilled and
completed 10 wells. We have a 50% working interest and
approximately a 40% net revenue interest in our North Bald
Prairie project. Average daily production in 2008 from North
Bald Prairie was
1.2 MMcf/d,
or a total of 447 MMcf. Average daily production in 2009
(through February) from North Bald Prairie was
1.2 MMcf/d
(net). We believe the potential exists for producing from
multiple zones in this area. Our primary targets are the Cotton
Valley Sands, Bossier and Cotton Valley Lime, all unconventional
tight gas formations where we believe we can apply our technical
and operational expertise to successfully recover natural gas.
Secondary targets include the shallower Rodessa, Pettit and
Travis Peak formations. We have identified 89 potential
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drilling locations in North Bald Prairie as of December 31,
2008, of which 31 are proved. In December 2008, EnCana notified
us that EnCana was exercising its right to become the operator
of record for joint interest wells in North Bald Prairie under
the carry and earning agreement. Either party may propose wells
under the joint operating agreement between the parties.
Southwest
Kentucky
Boomerang
(New Albany Shale)
Our Boomerang prospect is a 74,988 gross (44,759 net)
acre New Albany Shale play located in Southwest Kentucky in
the Illinois Basin. We have a 60% working interest and a net
revenue interest of approximately 50% in our Boomerang prospect.
We recorded an impairment expense from a non-cash write-off of
$2.3 million of drilling costs incurred for three test
wells we drilled in 2007. We currently are formulating a
development plan for this prospect.
Northeast
British Columbia
Montney
Tight Gas and Doig Shale
In August 2007, we acquired a non-operating, working interest
ranging from 11.9% to 25% in a lease acquisition and drilling
project targeting unconventional gas reserves in the emerging
Montney tight gas and Doig Shale play in Northeast British
Columbia. The project covers 31,231 gross (7,395 net)
acres. The primary targets are Triassic-aged tight gas and shale
gas. The Canadian operator has drilled three wells since the
project began in August 2007, without commercial success. We
have written off the carrying value of our minority equity
investment in the Canadian operator by recognizing a non-cash
write-off of $917,000. We also recorded an impairment expense
from a non-cash write-off of $4.1 million, which represents
our share of the drilling and completion costs related to our
interest in the joint drilling project. We plan to continue to
explore ways to recover our remaining carrying costs in this
project, including potential development of shallower productive
zones (such as the Doig Sand, North Pine, Halfway and Baldonnel)
in addition to the primary targets, change of operator and the
potential sale or farm-out of part or all of the parties
joint interest in the project.
Northern
New Mexico
El Vado
East (Mancos Shale)
Our El Vado East prospect is a 90,357 gross (79,793 net)
acre Mancos Shale play located in the Chama Basin in
Northern New Mexico in proximity to several productive fields,
including the Puerto Chiquito West, Puerto Chiquito East and the
Boulder fields, which collectively have produced in excess of
29 MMBoe of oil and gas. Our primary objective in El Vado
East is the Mancos Shale at 2,000 to 3,000 feet. We have a
90% working interest and a net revenue interest of approximately
72% in our El Vado East prospect.
Since April 2008 our leasehold in Northern New Mexico has been
the subject of regulatory proceedings and delays, including a
moratorium on all drilling on private lands in Rio Arriba
County, a proposed county drilling ordinance and potential state
rulemaking. In light of these regulatory proceedings and
continued expected delays in 2009, we currently have not
allocated any capital to El Vado East for 2009.
4
Natural
gas and oil reserves
The following table sets forth summary information regarding our
estimated proved reserves as of December 31, 2008 and 2007.
See Note 13 Disclosures about Oil and Gas
Producing Activities (unaudited) to our consolidated financial
statements for additional information. Our estimated total
proved reserves of natural gas and oil as of December 31,
2008 were 211.1 Bcfe. The 2008 reserves are composed of 82%
natural gas and 18% oil, condensate and NGLs. The proved
developed portion of total proved reserves at year end 2008 was
48%. Our reserve estimates and
PV-10
(defined below) for the years ended December 31, 2008 and
2007 are based on an independent engineering study of our oil
and gas properties prepared by DeGolyer and MacNaughton, our
independent reserve engineers.
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Estimated Proved Reserves
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Gas (MMcf)
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Oil and NGLs (MBbls)
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Total (MMcfe)
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December 31, 2008
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Ozona Northeast
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Proved Developed
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72,675
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550
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75,973
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Proved Undeveloped
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63,125
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887
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68,448
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Total Proved
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135,800
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1,437
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144,421
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Cinco Terry
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Proved Developed
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8,973
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2,464
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23,756
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Proved Undeveloped
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7,321
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2,466
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22,117
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Total Proved
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16,294
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4,930
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45,873
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North Bald Prairie
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Proved Developed
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2,569
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2,569
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Proved Undeveloped
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18,205
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18,205
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Total Proved
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20,774
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20,774
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Total
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Proved Developed
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84,217
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3,014
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102,298
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Proved Undeveloped
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88,651
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3,353
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108,770
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Total Proved
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172,868
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6,367
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211,068
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December 31, 2007
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Ozona Northeast
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Proved Developed
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65,725
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529
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68,899
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Proved Undeveloped
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67,441
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720
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71,763
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Total Proved
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133,166
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1,249
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140,662
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Cinco Terry
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Proved Developed
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2,421
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739
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6,855
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Proved Undeveloped
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4,140
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1,220
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11,459
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Total Proved
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6,561
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1,959
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18,314
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North Bald Prairie
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Proved Developed
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|
|
2,105
|
|
|
|
|
|
|
|
2,105
|
|
Proved Undeveloped
|
|
|
19,319
|
|
|
|
|
|
|
|
19,319
|
|
Total Proved
|
|
|
21,424
|
|
|
|
|
|
|
|
21,424
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed
|
|
|
70,251
|
|
|
|
1,268
|
|
|
|
77,859
|
|
Proved Undeveloped
|
|
|
90,900
|
|
|
|
1,940
|
|
|
|
102,541
|
|
Total Proved
|
|
|
161,151
|
|
|
|
3,208
|
|
|
|
180,400
|
|
5
The standardized measure of discounted future net cash flows for
our proved reserves at December 31, 2008 was
$142.6 million.
The present value of our proved reserves, discounted at 10%
(PV-10), was
estimated at $221.1 million, based on year end weighted
average prices of $6.04 per Mcf for natural gas, $39.60 per Bbl
for oil and $23.00 per Bbl for NGLs.
PV-10 is a
non-GAAP financial measure and generally differs from the
standardized measure of discounted future net cash flows, the
most directly comparable GAAP financial measure, because it does
not include the effects of income taxes on future cash flows.
See Reconciliation of non-GAAP financial measure
(PV-10)
below for our definition of
PV-10 and a
reconciliation of
PV-10 to the
standardized measure of discounted future net cash flows.
On December 31, 2008, the SEC released a Final Rule,
Modernization of Oil and Gas Reporting, updating its oil
and gas reporting requirements, including reserve reporting. The
new reporting requirements will be effective for our
2009 year-end proved reserve estimates. See
Managements Discussion and Analysis of Financial
Condition and Results of Operations and
Note 1 Summary of Significant Accounting
Policies for our discussion of the SECs new oil and gas
reporting requirements.
Reconciliation
of non-GAAP financial measure
(PV-10)
The following table shows our reconciliation of our
PV-10 to our
standardized measure of discounted future net cash flows (the
most directly comparable measure calculated and presented in
accordance with generally accepted accounting principles, or
GAAP). PV-10
is our estimate of the present value of future net revenues from
proved oil and gas reserves after deducting estimated production
and ad valorem taxes, future capital costs and operating
expenses, but before deducting any estimates of future income
taxes. The estimated future net revenues are discounted at an
annual rate of 10% to determine their present value.
We believe
PV-10 to be
an important measure for evaluating the relative significance of
our oil and gas properties and that the presentation of the
non-GAAP financial measure of
PV-10
provides useful information to investors because it is widely
used by professional analysts and sophisticated investors in
evaluating oil and gas companies. Because there are many unique
factors that can impact an individual company when estimating
the amount of future income taxes to be paid, we believe the use
of a pre-tax measure is valuable for evaluating our company. We
believe that most other companies in the oil and gas industry
calculate
PV-10 on the
same basis.
PV-10 should
not be considered as an alternative to the standardized measure
of discounted future net cash flows as computed under GAAP.
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
|
(In thousands)
|
|
|
PV-10
|
|
$
|
221,080
|
|
Less income taxes:
|
|
|
|
|
Undiscounted future income taxes
|
|
|
(157,503
|
)
|
10% discount factor
|
|
|
79,058
|
|
|
|
|
|
|
Future discounted income taxes
|
|
|
(78,445
|
)
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
142,635
|
|
|
|
|
|
|
No estimates of our reserves have been filed with or included in
reports to another federal authority or agency since year end.
6
Net
production, unit prices and costs
The following table sets forth summary information regarding our
production results, average sales prices and average production
costs during the years ended December 31, 2008, 2007 and
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Net production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
7,092
|
|
|
|
4,801
|
|
|
|
6,282
|
|
Oil (MBbls)
|
|
|
175
|
|
|
|
72
|
|
|
|
77
|
|
Natural gas liquids (MBbls)
|
|
|
102
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
8,755
|
|
|
|
5,305
|
|
|
|
6,744
|
|
Average net daily production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
24
|
|
|
|
15
|
|
|
|
18
|
|
Average realized sales price per unit (without the effects of
commodity derivatives):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
8.29
|
|
|
$
|
6.98
|
|
|
$
|
6.66
|
|
Oil (per Bbl)
|
|
|
93.79
|
|
|
|
70.31
|
|
|
|
62.65
|
|
Natural gas liquids (per Bbl)
|
|
|
45.46
|
|
|
|
46.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price (per Mcfe)
|
|
$
|
9.12
|
|
|
$
|
7.37
|
|
|
$
|
6.92
|
|
Average realized sales price per unit (with the effects of
commodity derivatives):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
8.71
|
|
|
$
|
7.96
|
|
|
$
|
7.65
|
|
Oil (per Bbl)
|
|
|
93.79
|
|
|
|
70.31
|
|
|
|
62.65
|
|
Natural gas liquids (per Bbl)
|
|
|
45.46
|
|
|
|
46.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price (per Mcfe)
|
|
$
|
9.46
|
|
|
$
|
8.26
|
|
|
$
|
7.84
|
|
Expenses (per Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
0.87
|
|
|
$
|
0.72
|
|
|
$
|
0.58
|
|
Severance and production taxes
|
|
|
0.48
|
|
|
|
0.31
|
|
|
|
0.26
|
|
Exploration
|
|
|
0.17
|
|
|
|
0.17
|
|
|
|
0.24
|
|
Impairment of non-producing properties
|
|
|
0.73
|
|
|
|
0.05
|
|
|
|
0.08
|
|
General and administrative
|
|
|
1.01
|
|
|
|
2.39
|
|
|
|
0.36
|
|
Depletion, depreciation and amortization
|
|
|
2.71
|
|
|
|
2.47
|
|
|
|
2.16
|
|
Productive
wells
The following table sets forth the number of productive oil and
gas wells in which we owned a working interest at
December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Total
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Ozona Northeast
|
|
|
380.0
|
|
|
|
380.0
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
381.0
|
|
|
|
381.0
|
|
Cinco Terry
|
|
|
46.0
|
|
|
|
23.0
|
|
|
|
8.0
|
|
|
|
4.0
|
|
|
|
54.0
|
|
|
|
27.0
|
|
North Bald Prairie
|
|
|
10.0
|
|
|
|
5.0
|
|
|
|
0.0
|
|
|
|
0.0
|
|
|
|
10.0
|
|
|
|
5.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Productive Wells
|
|
|
436.0
|
|
|
|
408.0
|
|
|
|
9.0
|
|
|
|
5.0
|
|
|
|
445.0
|
|
|
|
413.0
|
|
7
Acreage
The following table summarizes our developed and undeveloped
acreage as of December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Ozona Northeast
|
|
|
30,199
|
|
|
|
29,385
|
|
|
|
18,970
|
|
|
|
14,659
|
|
|
|
49,169
|
|
|
|
44,044
|
|
Cinco Terry
|
|
|
5,267
|
|
|
|
2,660
|
|
|
|
40,021
|
|
|
|
16,806
|
|
|
|
45,288
|
|
|
|
19,466
|
|
North Bald Prairie
|
|
|
3,481
|
|
|
|
1,701
|
|
|
|
5,820
|
|
|
|
2,660
|
|
|
|
9,301
|
|
|
|
4,361
|
|
Boomerang
|
|
|
|
|
|
|
|
|
|
|
74,988
|
|
|
|
44,759
|
|
|
|
74,988
|
|
|
|
44,759
|
|
Northeast British Columbia
|
|
|
3,896
|
|
|
|
561
|
|
|
|
27,335
|
|
|
|
6,834
|
|
|
|
31,231
|
|
|
|
7,395
|
|
El Vado East
|
|
|
|
|
|
|
|
|
|
|
90,357
|
|
|
|
79,793
|
|
|
|
90,357
|
|
|
|
79,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
42,843
|
|
|
|
34,307
|
|
|
|
257,491
|
|
|
|
165,511
|
|
|
|
300,334
|
|
|
|
199,818
|
|
The following table sets forth the number of gross and net
undeveloped acres as of December 31, 2008 that will expire
over the next three years by region unless production is
established within the spacing or producing units covering the
acreage prior to the expiration dates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Ozona Northeast
|
|
|
3,062
|
|
|
|
2,313
|
|
|
|
|
|
|
|
13
|
|
|
|
15,908
|
|
|
|
12,333
|
|
Cinco Terry
|
|
|
3,118
|
|
|
|
2,223
|
|
|
|
5,390
|
|
|
|
3,305
|
|
|
|
24,696
|
|
|
|
7,842
|
|
North Bald Prairie
|
|
|
3,174
|
|
|
|
2,098
|
|
|
|
2,646
|
|
|
|
562
|
|
|
|
|
|
|
|
|
|
Boomerang(1)
|
|
|
|
|
|
|
|
|
|
|
6,777
|
|
|
|
4,066
|
|
|
|
146
|
|
|
|
88
|
|
Northeast British Columbia
|
|
|
|
|
|
|
|
|
|
|
22,784
|
|
|
|
5,696
|
|
|
|
2,595
|
|
|
|
649
|
|
El Vado East(2)
|
|
|
90,357
|
|
|
|
79,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
99,711
|
|
|
|
86,427
|
|
|
|
37,597
|
|
|
|
13,642
|
|
|
|
43,345
|
|
|
|
20,912
|
|
|
|
|
(1) |
|
Assumes the exercise of options to extend the current primary
terms by three to five additional years (beginning July 2009
through December 2011) on 67,995 gross (40,565 net)
acres. Options to extend 58,548 gross (35,027 net) acres
have an exercise price of $2.00 per year per net acre for five
total available years. Options to extend 7,510 gross (4,374
net) acres have an exercise price of $7 per year per net acre
for five total available years. Options to extend the remaining
1,937 gross (1,164 net) acres have a weighted average
exercise price of $38 per net acre for three to five total
available years. |
|
(2) |
|
We have an eight-well drilling commitment during the primary
term, which expires in April 2009. As of the filing of this
annual report on
Form 10-K,
the drilling commitment was extended by force majeure under the
lease. If we meet the drilling commitment (as extended by force
majeure), we will have two options to extend the primary term by
one year each for $15 per net acre, for a total extension of two
years at $30 per net acre. If we are not able to meet the
drilling commitment, as extended by force majeure, and we are
otherwise not able to negotiate appropriate extensions under the
lease, the lease will expire. See Regulation
New Mexico for additional information on our
New Mexico lease and the delays in drilling in New Mexico. |
8
Drilling
activity
The following table sets forth information on our drilling
activity for the last three years. The information should not be
considered indicative of future performance, nor should it be
assumed that there is necessarily any correlation between the
number of productive wells drilled, quantities of reserves found
or economic value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive(1)
|
|
|
83.0
|
|
|
|
54.5
|
|
|
|
51.0
|
|
|
|
46.0
|
|
|
|
81.0
|
|
|
|
53.3
|
|
Non-productive(2)
|
|
|
11.0
|
|
|
|
7.5
|
|
|
|
5.0
|
|
|
|
4.0
|
|
|
|
6.0
|
|
|
|
4.2
|
|
Exploratory wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.0
|
|
|
|
1.0
|
|
Non-productive(3)
|
|
|
2.0
|
|
|
|
0.5
|
|
|
|
1.0
|
|
|
|
0.7
|
|
|
|
|
|
|
|
|
|
Total wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
83.0
|
|
|
|
54.5
|
|
|
|
51.0
|
|
|
|
46.0
|
|
|
|
83.0
|
|
|
|
54.3
|
|
Non-productive
|
|
|
13.0
|
|
|
|
8.0
|
|
|
|
6.0
|
|
|
|
4.7
|
|
|
|
6.0
|
|
|
|
4.2
|
|
|
|
|
(1) |
|
Of the 83 gross productive wells drilled in 2008, 10 were
waiting on completion at December 31, 2008. |
|
(2) |
|
Of the 11 gross non-productive wells drilled in 2008, one
well will be completed as a salt water disposal well in North
Bald Prairie during the first half of 2009. |
|
(3) |
|
The two gross exploratory wells drilled in 2008 were drilled by
the Canadian operator of our Northeast British Columbia project. |
Wells drilled in 2007 are pro forma for the November 14,
2007 acquisition of Neo Canyon Exploration, L.P.s 30%
working interest in Ozona Northeast, which we refer to as the
Neo Canyon interest, as if the acquisition occurred on
January 1, 2007.
Markets
and customers
The revenues generated by our operations are highly dependent
upon the prices of, and supply and demand for, oil and gas. The
price we receive for our oil and gas production depends on
numerous factors beyond our control, including seasonality, the
condition of the United States and global economies,
particularly in the manufacturing sectors, political conditions
in other oil and gas producing countries, the extent of domestic
production and imports of oil and gas, the proximity and
capacity of gas pipelines and other transportation facilities,
supply and demand for oil and gas, the marketing of competitive
fuels and the effects of federal, state and local regulation.
The oil and gas industry also competes with other industries in
supplying the energy and fuel requirements of industrial,
commercial and individual consumers.
During the year ended December 31, 2008, Ozona Pipeline
Energy Company, which we refer to as Ozona Pipeline, and WTG
Benedum/Belvan Partners, LP, were our most significant
purchasers, accounting for approximately 61.9% and 15.8%,
respectively, of our total 2008 oil and gas sales excluding
realized commodity derivative settlements.
Commodity
derivative activity
We enter into financial swaps and collars to mitigate portions
of the risk of market price fluctuations related to future oil
and gas production.
All derivative instruments are recorded on the balance sheet at
fair value. Changes in the derivatives fair value are
currently recognized in the statement of operations unless
specific commodity derivative accounting criteria are met. For
qualifying cash-flow commodity derivatives, the gain or loss on
the derivative is deferred in accumulated other comprehensive
income (loss) to the extent the commodity derivative is
effective. The
9
ineffective portion of the commodity derivative is recognized
immediately in the statement of operations. Gains and losses on
commodity derivative instruments included in accumulated other
comprehensive income (loss) are reclassified to oil and gas
sales revenue in the period that the related production is
delivered. Derivative contracts that do not qualify for
commodity derivative accounting treatment are recorded as
derivative assets and liabilities at fair value in the balance
sheet, and the associated unrealized gains and losses are
recorded as current income or expense in the statement of
operations.
Historically, we have not designated our derivative instruments
as cash-flow commodity derivatives. We record our open
derivative instruments at fair value on our consolidated balance
sheets as either unrealized gains or losses on commodity
derivatives. We record changes in such fair value in earnings on
our consolidated statements of operations under the caption
entitled unrealized gain (loss) on commodity
derivatives.
Title to
properties
Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and
other burdens, including other mineral encumbrances and
restrictions. We do not believe that any of these burdens
materially interfere with our use of the properties in the
operation of our business.
We believe that we have generally satisfactory title to or
rights in all of our producing properties. As is customary in
the oil and gas industry, we make a general investigation of
title at the time we acquire undeveloped properties. We receive
title opinions of counsel before we commence drilling
operations. We believe that we have satisfactory title to all of
our other assets. Although title to our properties is subject to
encumbrances in certain cases, we believe that none of these
burdens will materially detract from the value of our properties
or from our interest therein or will materially interfere with
our use of the properties in the operation of our business.
Competition
The oil and gas industry is highly competitive, and we compete
with a substantial number of other companies that have greater
resources. Many of these companies explore for, produce and
market oil and gas, carry on refining operations and market the
resultant products on a worldwide basis. The primary areas in
which we encounter substantial competition are in locating and
acquiring desirable leasehold acreage for our drilling and
development operations, locating and acquiring attractive
producing oil and gas properties, and obtaining purchasers and
transporters of the oil and gas we produce. There is also
competition between producers of oil and gas and other
industries producing alternative energy and fuel. Furthermore,
competitive conditions may be substantially affected by various
forms of energy legislation
and/or
regulation considered from time to time by the United States
government. However, it is not possible to predict the nature of
any such legislation or regulation that may ultimately be
adopted or its effects upon our future operations. Such laws and
regulations may, however, substantially increase the costs of
exploring for, developing or producing oil and gas and may
prevent or delay the commencement or continuation of a given
operation. The effect of these risks cannot be accurately
predicted.
Regulation
The oil and gas industry in the United States is subject to
extensive regulation by federal, state and local authorities. At
the federal level, various federal rules, regulations and
procedures apply, including those issued by the United States
Department of Interior, and the United States Department of
Transportation (Office of Pipeline Safety). At the state and
local level, various agencies and commissions regulate drilling,
production and midstream activities. These federal, state and
local authorities have various permitting, licensing and bonding
requirements. Various remedies are available for enforcement of
these federal, state and local rules, regulations and
procedures, including fines, penalties, revocation of permits
and licenses, actions affecting the value of leases, wells or
other assets, and suspension of production. As a result, there
can be no assurance that we will not incur liability for fines
and penalties or otherwise subject us to the various remedies as
are
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available to these federal, state and local authorities.
However, we believe that we are currently in material compliance
with these federal, state and local rules, regulations and
procedures.
Transportation
and sale of gas
The Federal Energy Regulation Commission, or FERC,
regulates interstate gas pipeline transportation rates and
service conditions. Although the FERC does not regulate gas
producers such as us, the agencys actions are intended to
foster increased competition within all phases of the gas
industry and its regulation of third-party pipelines and
facilities could indirectly affect our ability to transport or
market our production. To date, FERCs pro-competition
policies have not materially affected our business or
operations. It is unclear what impact, if any, future rules or
increased competition within the gas industry will have on our
gas sales efforts.
FERC or other federal or state regulatory agencies may consider
additional proposals or proceedings that might affect the gas
industry. In addition, new legislation may affect the industries
and markets in which we operate. We cannot predict when or if
these proposals will become effective or any effect they may
have on our operations. We do not believe, however, that any of
these proposals will affect us any differently than other gas
producers with which we compete.
Regulation
of production
Oil and gas production is regulated under a wide range of
federal and state statutes, rules, orders and regulations. State
and federal statutes and regulations require permits for
drilling operations, drilling bonds and reports concerning
operations. The states in which we own and operate properties
have regulations governing conservation matters, including
provisions for the unitization or pooling of oil and gas
properties, the establishment of maximum rates of production
from oil and gas wells, the regulation of spacing, and
requirements for plugging and abandonment of wells. Also, each
state generally imposes an ad valorem, production or severance
tax with respect to production and sale of oil, gas and gas
liquids within its jurisdiction.
Environmental
regulations
In the United States, the exploration for and development of oil
and gas and the drilling and operation of wells, fields and
gathering systems are subject to extensive federal, state and
local laws and regulations governing environmental protection as
well as discharge of materials into the environment. Similar
environmental laws exist in Canada. These laws and regulations
may, among other things:
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require the acquisition of various permits before drilling
commences,
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require the installation of expensive pollution control
equipment,
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restrict the types, quantities and concentration of various
substances that can be released into the environment in
connection with oil and gas drilling production, transportation
and processing activities,
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suspend, limit or prohibit construction, drilling and other
activities in certain lands lying within wilderness, wetlands
and other protected areas, and
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require remedial measures to mitigate and remediate pollution
from historical and ongoing operations, such as the closure of
waste pits and plugging of abandoned wells.
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These laws, rules and regulations may also restrict the rate of
oil and gas production below the rate that would otherwise be
possible. The regulatory burden on the oil and gas industry
increases the cost of doing business in the industry and
consequently affects profitability.
Governmental authorities have the power to enforce compliance
with environmental laws, regulations and permits, and violations
are subject to injunction, as well as administrative, civil and
criminal penalties. The effects of existing and future laws and
regulations could have a material adverse impact on our
business, financial condition and results of operations. While
we believe that we are in substantial compliance with
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existing environmental laws and regulations and that continued
compliance with current requirements would not have a material
adverse effect on us, there is no assurance that this will
continue in the future.
The following is a summary of some of the existing laws, rules
and regulations to which our business operations are subject.
Comprehensive
Environmental Response, Compensation and Liability
Act
The Comprehensive Environmental Response, Compensation and
Liability Act of 1980, or CERCLA, also known as the Superfund
law, and comparable state statutes impose strict, and under
certain circumstances, joint and several liability, on classes
of persons who are considered to be responsible for the release
of a hazardous substance into the environment. These persons
include the owner or operator of the site where the release
occurred, and anyone who disposed or arranged for the disposal
of a hazardous substance released at the site. Under CERCLA,
such persons may be subject to strict, joint and several
liabilities for the costs of cleaning up the hazardous
substances that have been released into the environment, for
damages to natural resources and for the costs of certain health
studies. In addition, it is not uncommon for neighboring
landowners and other third-parties to file claims for personal
injury and property damage allegedly caused by the hazardous
substances released into the environment. While we generate
materials in the course of our operations that may be regulated
as hazardous substances, we have not received notification that
we may be potentially responsible for cleanup costs under CERCLA.
Waste
handling
The Resource Conservation and Recovery Act, or RCRA, and
comparable state statutes, regulate the generation,
transportation, treatment, storage, disposal and cleanup of
hazardous and non-hazardous wastes. Under the auspices of the
federal Environmental Protection Agency, or EPA, the individual
states administer some or all of the provisions of RCRA,
sometimes in conjunction with their own, more stringent
requirements. Drilling fluids, produced waters and most of the
other wastes associated with the exploration, development,
exploitation and production of oil or gas are currently
regulated under RCRAs non-hazardous waste provisions.
However, it is possible that certain oil and gas exploration and
production wastes now classified as non-hazardous could be
classified as hazardous wastes in the future. Any such change
could result in an increase in our operating expenses, which
could have a material adverse effect on our business, financial
condition and results of operations.
We currently own or lease, and have in the past owned or leased,
properties that for many years have been used for oil and gas
exploration, production and development activities. Although we
used operating and disposal practices that were standard in the
industry at the time, petroleum hydrocarbons or wastes may have
been disposed of or released on, under or from the properties
owned or leased by us or on, under or from other locations where
such wastes have been taken for disposal. In addition, some of
these properties have been operated by third parties whose
treatment and disposal or release of petroleum hydrocarbons and
wastes was not under our control. These properties and the
materials disposed or released on, at, under or from them may be
subject to CERCLA, RCRA and analogous state laws. Under such
laws, we could be required to remove or remediate previously
disposed wastes or contamination, or to perform remedial
activities to prevent future contamination.
Air
emissions
The federal Clean Air Act and comparable state laws regulate
emissions of various air pollutants through air emissions
permitting programs and the imposition of other requirements. In
addition, the EPA has developed, and continues to develop,
stringent regulations governing emissions of hazardous and toxic
air pollutants at specified sources. These regulatory programs
may require us to obtain permits before commencing construction
on a new source of air emissions and may require us to reduce
emissions at existing facilities. As a result, we may be
required to incur increased capital and operating costs.
Additionally, federal and state regulatory agencies can impose
administrative, civil and criminal penalties for non-compliance
with air permits or other requirements of the federal Clean Air
Act and analogous state laws and regulations.
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In February 2005, the Kyoto Protocol to the United Nations
Framework Convention on Climate Change entered into force.
Pursuant to the Protocol, adopting countries are required to
implement national programs to reduce emissions of certain
gases, generally referred to as greenhouse gases, which are
suspected of contributing to global warming. The United States
is not currently a participant in the Protocol. However,
Congress has enacted legislation directed at reducing greenhouse
gas emissions and the EPA may be required to regulate greenhouse
gas emissions, and many states have already adopted legislation
or undertaken regulatory initiatives addressing greenhouse gas
emissions from various sources. The oil and gas exploration and
production industry is a direct source of certain greenhouse gas
emissions, namely carbon dioxide and methane, and future
restrictions on such emissions would likely adversely impact our
future operations, results of operations and financial
condition. At this time, although it is not possible to
accurately estimate how potential future laws or regulations
addressing greenhouse gas emissions would impact our business,
passage of such laws or regulation affecting areas in which we
conduct business could have an adverse effect on our operations.
Water
discharges
The Federal Water Pollution Control Act, also known as the Clean
Water Act, and analogous state laws, impose restrictions and
strict controls with respect to the discharge of pollutants,
including spills and leaks of oil and other substances into
regulated waters, including wetlands. The discharge of
pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by the EPA or an
analogous state agency. Federal and state regulatory agencies
can impose administrative, civil and criminal penalties for
non-compliance with discharge permits or other requirements of
the Clean Water Act and analogous state laws and regulations.
OSHA
and other laws and regulations
We are subject to the requirements of the federal Occupational
Safety and Health Act, or OSHA, and comparable state statutes.
The OSHA hazard communication standard, the EPA community
right-to-know regulations under the Title III of CERCLA and
similar state statutes require that we organize
and/or
disclose information about hazardous materials used or produced
in our operations. We believe that we are in substantial
compliance with these applicable requirements and with other
OSHA and comparable requirements.
We believe that we are in substantial compliance with all
existing environmental laws and regulations that apply to our
current operations and that our ongoing compliance with existing
requirements will not have a material adverse effect on our
financial condition or results of operations. We did not incur
any material capital expenditures for remediation or pollution
control activities for the year ended December 31, 2008. In
addition, as of the date of this annual report, we are not aware
of any environmental issues or claims that will require material
capital expenditures during 2009. However, the passage of more
stringent laws or regulations in the future could have a
negative effect on our business, financial condition and results
of operations, including our ability to develop our undeveloped
acreage. For example, see our discussion of current regulatory
proceedings in New Mexico below.
New
Mexico
In April 2008, the Board of County Commissioners of Rio Arriba
County, New Mexico imposed a moratorium on all oil and gas
drilling on private lands in Rio Arriba County, pending the
adoption of an ordinance that would regulate oil and gas
operations. The moratorium covers all of our El Vado East
prospect in Rio Arriba County. In February 2009, the Board of
Commissioners extended the moratorium through May 19, 2009.
In January 2009, the Board of Commissioners published a draft
oil and gas drilling ordinance for the county. The draft
ordinance is broad in its scope and application and would
require submission of applications for a special use and
development permits, along with a number of reports, plans,
assessments and other supporting materials.
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In addition to the county moratorium and proposed county
regulations, in July 2008, the Governor of New Mexico
directed the New Mexico Oil Conservation Division, or OCD, to
propose special rules for oil and gas operations in Eastern Rio
Arriba County, including our leasehold in El Vado East. Under
the Governors directive, these new rules would be proposed
and adopted in a rulemaking proceeding through the New Mexico
Oil Conservation Commission. The OCD recently has proposed
special rules for portions of Santa Fe County and the
Galisteo Basin that will materially increase the time and cost
to conduct drilling operations in that area.
In light of the regulatory proceedings impacting our leasehold
in Rio Arriba County, we currently have not allocated any
capital to El Vado East for 2009. If adopted, the state and
county rules and ordinances will increase the time and cost to
explore for oil and gas in El Vado East and may render the
project uneconomic for us.
In addition, ongoing delays in New Mexico affect our mineral
lease for El Vado East. Our lease currently requires us to drill
a minimum of eight wells before the primary term of the lease
expires on April 2, 2009. The lease also provides that if
our drilling operations are delayed or prevented as a result of
a governmental or regulatory order or by failure to obtain
permits, which are events of force majeure, then our
drilling commitment will be extended until 60 days after
the cause of the delay is removed, as long as the primary term
of the lease is not extended by more than four years. We have
notified the lessor of the delays in El Vado East, which began
in April 2008, and invoked the force majeure provision of the
lease. Our inability to meet this drilling commitment, as
extended by force majeure, or otherwise negotiate appropriate
extensions under the lease, could result in the expiration of
the lease and write-off of our investment in El Vado East, the
current carrying value of which is $2.7 million.
Employees
At February 28, 2009, we had 36 full-time employees.
None of our employees are represented by a labor union or
covered by any collective bargaining agreement. We believe that
our relations with our employees are excellent.
Insurance
matters
As is common in the oil and gas industry, we will not insure
fully against all risks associated with our business either
because such insurance is not available or because premium costs
are considered prohibitive. A loss not fully covered by
insurance could have a material adverse effect on our business,
financial condition and results of operations.
Available
information
We maintain an internet website under the name
www.approachresources.com We make available, free of
charge, on our website, the annual report on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K
and amendments to those reports, as soon as reasonably
practicable after providing such reports to the SEC. Also, the
charters of our Audit Committee and Compensation and Nominating
Committee, and our Code of Conduct are available on our website
and in print to any stockholder who provides a written request
to the Corporate Secretary at One Ridgmar Centre,
6500 W. Freeway, Suite 800, Fort Worth,
Texas 76116.
We file annual reports on
Form 10-K,
quarterly reports on
Form 10-Q
and current reports on
Form 8-K,
proxy statements and other documents with the SEC under the
Securities Exchange Act of 1934 (the Exchange Act).
The public may read and copy any materials that we file with the
SEC at the SECs Public Reference Room at
100 F Street, NE, Washington DC 20549. The public may
obtain information on the operation of the Public Reference Room
by calling the SEC at
1-800-SEC-0330.
Also, the SEC maintains an internet website that contains
reports, proxy and information statements, and other information
regarding issuers, including Approach, that file electronically
with the SEC. The public can obtain any document we file with
the SEC at www.sec.gov. Information contained on or
connected to our website is not incorporated by reference into
this
Form 10-K
and should not be considered part of this report or any other
filing that we make with the SEC.
14
You should carefully consider the risk factors set forth below
as well as the other information contained in this report before
investing in our common stock. Any of the following risks could
materially and adversely affect our business, financial
condition or results of operations. In such a case, you may lose
all or part of your investment. The risks described below are
not the only risks facing us. Additional risks and uncertainties
not currently known to us or those we currently view to be
immaterial may also materially adversely affect our business,
financial condition or results of operations.
Risks
related to the oil and natural gas industry and our
business
Oil and gas prices are volatile, and a decline in gas or
oil prices could significantly affect our business, financial
condition or results of operations and our ability to meet our
capital expenditure requirements and financial
commitments.
Our revenues, profitability and cash flow depend substantially
upon the prices and demand for oil and gas. The markets for
these commodities are volatile, and even relatively modest drops
in prices can affect significantly our financial results and
impede our growth. Prices for oil and gas fluctuate widely in
response to relatively minor changes in the supply and demand
for oil and gas, market uncertainty and a variety of additional
factors beyond our control, such as:
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the level of domestic and foreign consumer demand for oil and
gas,
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domestic and foreign supply of oil and gas, including LNG,
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overall United States and global economic conditions,
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price and quantity of foreign imports,
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commodity processing, gathering and transportation availability
and the availability of refining capacity,
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domestic and foreign governmental regulations,
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political conditions in or affecting other gas producing and oil
producing countries,
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the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil price and
production controls,
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weather conditions, including unseasonably warm winter weather
and tropical storms,
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technological advances affecting oil and gas
consumption, and
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price and availability of alternative fuels.
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Further, oil prices and gas prices do not necessarily fluctuate
in direct relationship to each other. Because more than 82% of
our estimated proved reserves as of December 31, 2008 were
gas reserves, our financial results are more sensitive to
movements in gas prices. Recent gas prices have been extremely
volatile and we expect this volatility to continue. For example,
from January 1, 2008 to December 31, 2008, the NYMEX
gas spot price ranged from a high of $13.58 per MMBtu to a low
of $5.29 per MMBtu.
The results of higher investment in the exploration for and
production of oil and gas and other factors, such as global
economic and financial conditions discussed below, may cause the
price of gas to fall. Lower oil and gas prices may not only
cause our revenues to decrease but also may reduce the amount of
oil and gas that we can produce economically. Substantial
decreases in oil and gas prices would render uneconomic some or
all of our drilling locations. This may result in our having to
make substantial downward adjustments to our estimated proved
reserves and could have a material adverse effect on our
business, financial condition and results of operations.
Further, if oil and gas prices significantly decline for an
extended period of time, we may, among other things, be unable
to maintain or increase our borrowing capacity, repay current or
future debt or obtain additional capital on attractive terms,
all of which can affect the value of our common stock.
15
The deterioration of global economic and financial
conditions and an extended decline in the price of oil and
natural gas would negatively impact our business, financial
condition and results of operations.
The global economic and financial crisis could lead to an
extended national or global economic recession. The slowdown in
economic activity caused by the current recession will likely
reduce national and worldwide demand for oil and natural gas and
result in lower commodity prices. Substantial decreases in oil
and natural gas prices could have a material adverse effect on
our business, financial condition and results of operations,
limit our access to liquidity and credit and hinder our ability
to fund our development program. The inability to execute our
development program could also lead to low production and
reserve growth.
If credit and capital markets do not improve, we may not
be able to obtain funding under our current revolving credit
facility or fund on acceptable terms. The inability to obtain
funding could deter or prevent us from meeting our future
capital needs to fund our development program.
Capital and credit markets have experienced unprecedented
volatility and disruption and continue to be unpredictable.
Given the current levels of market volatility and disruption,
the availability of funds from those markets has diminished
substantially. Further, arising from concerns about the
stability of financial markets generally and the solvency of
counterparties specifically, the cost of accessing the credit
markets has increased as many lenders have raised interest
rates, enacted tighter lending standards or altogether ceased to
provide funding to borrowers. Additionally, even if lenders are
able to provide funding to borrowers, interest rates may rise in
the future and therefore increase the cost of outstanding
borrowings that we may incur under our revolving credit facility.
Moreover, we may be unable to obtain adequate funding under our
current revolving credit facility. First, our lenders may be
unwilling or unable to meet their funding commitments. Second,
our borrowing base under our current revolving credit facility
is redetermined semiannually. Our lenders have substantial
ability to reduce our borrowing base on the basis of subjective
factors. If oil and gas prices significantly decline for an
extended period of time, our lenders could redetermine the
borrowing base by evaluating our reserves at substantially lower
oil and gas prices. Such determination could result in a
negative revision to our proved reserve value and reduce our
borrowing base.
Due to these capital and credit market conditions, we cannot be
certain that funding will be available if needed and to the
extent required, on acceptable terms. If funding is not
available when needed, or is available only on unfavorable
terms, we may be unable to meet our obligations as they come due
or be required to post collateral to support our obligations, or
we may be unable to implement our development program, grow our
existing business through acquisitions or joint ventures or
otherwise take advantage of business opportunities or respond to
competitive pressures, any of which could have a material
adverse effect on our business, financial condition and results
of operations.
Our lenders can limit our borrowing capabilities, which
may materially impact our operations.
At December 31, 2008, we had approximately
$43.5 million of outstanding debt under our revolving
credit facility, and our borrowing base was $100.0 million.
The borrowing base limitation under our credit facility is
semi-annually redetermined based upon a number of factors,
including commodity prices and reserve levels. In addition to
such semi-annual redeterminations, our lenders may request one
additional redetermination during any twelve-month period. Upon
a redetermination, our borrowing base could be substantially
reduced, and in the event the amount outstanding under our
credit facility at any time exceeds the borrowing base at such
time, we may be required to repay a portion of our outstanding
borrowings. We utilize cash flow from operations and bank
borrowings to fund our exploration and development activities. A
reduction in our borrowing base could limit our activities. In
addition, we may significantly alter our capitalization in order
to make future acquisitions or develop our properties. These
changes in capitalization may significantly increase our level
of debt. If we incur additional debt for these or other
purposes, the related risks that we now face could intensify. A
higher level of debt also increases the risk that we may default
on our debt obligations. Our ability to meet our debt
obligations and to reduce our level of debt depends on our
future performance which is affected by general economic
conditions and financial, business and other factors, many of
which are beyond our control.
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Drilling and exploring for, and producing, oil and gas are
high risk activities with many uncertainties that could
adversely affect our business, financial condition or results of
operations.
Drilling and exploration are the main methods we use to replace
our reserves. However, drilling and exploration operations may
not result in any increases in reserves for various reasons.
Exploration activities involve numerous risks, including the
risk that no commercially productive gas or oil reservoirs will
be discovered. In addition, the future cost and timing of
drilling, completing and producing wells is often uncertain.
Furthermore, drilling operations may be curtailed, delayed or
canceled as a result of a variety of factors, including:
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lack of acceptable prospective acreage,
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inadequate capital resources,
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unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents,
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adverse weather conditions, including tornados,
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unavailability or high cost of drilling rigs, equipment or labor,
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reductions in oil and gas prices,
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limitations in the market for oil and gas,
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surface access restrictions,
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title problems,
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compliance with governmental regulations, and
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mechanical difficulties.
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Our decisions to purchase, explore and develop prospects or
properties depend in part on data obtained through geophysical
and geological analyses, production data and engineering
studies, the results of which are often uncertain. Even when
used and properly interpreted,
3-D seismic
data and visualization techniques only assist geoscientists and
geologists in identifying subsurface structures and hydrocarbon
indicators. They do not allow the interpreter to know
conclusively if hydrocarbons are present or producible
economically. In addition, the use of
3-D seismic
and other advanced technologies require greater pre-drilling
expenditures than traditional drilling strategies.
Currently, all of our producing properties are located in
four counties in Texas, and our proved reserves are primarily
attributable to three fields, making us vulnerable to risks
associated with having our production concentrated in a small
area.
All of our producing properties are geographically concentrated
in four counties in Texas, and our proved reserves are primarily
attributable to three fields in that area, Ozona Northeast and
the Angus and Holt fields in Cinco Terry. As a result of this
concentration, we are disproportionately exposed to the natural
decline of production from these fields, and particularly Ozona
Northeast, as well as the impact of delays or interruptions of
production from these wells caused by significant governmental
regulation, transportation capacity constraints, curtailments of
production, natural disasters, interruption of transportation of
gas produced from the wells in these basins or other events that
impact these areas.
We have leases and options for undeveloped acreage that
may expire in the near future.
As of December 31, 2008, we held mineral leases in each of
our areas of operations that are still within their original
lease term and are not currently held by production. Unless we
establish commercial production on the properties subject to
these leases, most of these leases will expire between 2009 and
2015. Options covering approximately 3,118 gross acres in
our Cinco Terry project are scheduled to expire during 2009. If
these leases or options expire, we will lose our right to
develop the related properties. See Items 1. and 2.
Business and Properties Acreage for a
table summarizing the expiration schedule of our undeveloped
acreage over the next three years.
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Identified drilling locations that we decide to drill may
not yield gas or oil in commercially viable quantities and are
susceptible to uncertainties that could materially alter the
occurrence or timing of their drilling.
Our drilling locations are in various stages of evaluation,
ranging from locations that are ready to be drilled to locations
that will require substantial additional evaluation and
interpretation. There is no way to predict in advance of
drilling and testing whether any particular drilling location
will yield gas or oil in sufficient quantities to recover
drilling or completion costs or to be economically viable. The
use of seismic data and other technologies and the study of
producing fields in the same area will not enable us to know
conclusively before drilling whether gas or oil will be present
or, if present, whether gas or oil will be present in commercial
quantities. The analysis that we perform may not be useful in
predicting the characteristics and potential reserves associated
with our drilling locations. As a result, we may not find
commercially viable quantities of oil and gas.
Our drilling locations represent a significant part of our
growth strategy. Our ability to drill and develop these
locations depends on a number of factors, including oil and gas
prices, costs, the availability of capital, seasonal conditions,
regulatory approvals and drilling results. Because of these
uncertainties, we do not know when the unproved drilling
locations we have identified will be drilled or if they will
ever be drilled or if we will be able to produce gas or oil from
these or any proved drilling locations. As such, our actual
drilling activities may be materially different from those
presently identified, which could adversely affect our business,
results of operations or financial condition.
Unless we replace our oil and gas reserves, our reserves
and production will decline.
Our future oil and gas production depends on our success in
finding or acquiring additional reserves. If we fail to replace
reserves through drilling or acquisitions, our level of
production and cash flows will be affected adversely. In
general, production from oil and gas properties declines as
reserves are depleted, with the rate of decline depending on
reservoir characteristics. Our total proved reserves will
decline as reserves are produced unless we conduct other
successful exploration and development activities or acquire
properties containing proved reserves, or both. Our ability to
make the necessary capital investment to maintain or expand our
asset base of oil and gas reserves would be impaired to the
extent cash flow from operations is reduced and external sources
of capital become limited or unavailable. We may not be
successful in exploring for, developing or acquiring additional
reserves.
Our actual production, revenues and expenditures related
to our reserves are likely to differ from our estimates of our
proved reserves. We may experience production that is less than
estimated and drilling costs that are greater than estimated in
our reserve reports. These differences may be material.
The proved oil and gas reserve information included in this
report represents estimates. Petroleum engineering is a
subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and
of future net cash flows necessarily depend upon a number of
variable factors and assumptions, including:
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historical production from the area compared with production
from other similar producing areas,
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the assumed effects of regulations by governmental agencies,
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assumptions concerning future oil and gas prices, and
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assumptions concerning future operating costs, severance and
excise taxes, development costs and workover and remedial costs.
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Because all reserve estimates are to some degree subjective,
each of the following items may differ materially from those
assumed in estimating proved reserves:
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the quantities of oil and gas that are ultimately recovered,
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the production and operating costs incurred,
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the amount and timing of future development
expenditures, and
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future oil and gas prices.
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18
As of December 31, 2008, approximately 52% of our proved
reserves were proved undeveloped. Estimates of proved
undeveloped reserves are even less reliable than estimates of
proved developed reserves.
Furthermore, different reserve engineers may make different
estimates of reserves and future net revenues based on the same
available data. Our actual production, revenues and expenditures
with respect to reserves will likely be different from estimates
and the differences may be material. The
PV-10
included in this report should not be considered as the current
market value of the estimated oil and gas reserves attributable
to our properties. As required by the SEC,
PV-10 is
generally based on prices and costs as of the date of the
measurement (December 31, 2008), while actual future prices
and costs may be materially higher or lower. If gas prices
decline by $1.00 per Mcf from $6.04 per Mcf to $5.04 per Mcf,
then our
PV-10 as of
December 31, 2008 would decrease from $221.1 million
to $163.2 million. The average market price received for
our natural gas production for the month of December 31,
2008, after basis and Btu adjustments, was $6.02 per Mcf.
Actual future net revenues also will be affected by factors such
as:
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the amount and timing of actual production,
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supply and demand for oil and gas,
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increases or decreases in consumption, and
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changes in governmental regulations or taxation.
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The unavailability or high cost of drilling rigs,
equipment, supplies, personnel and oilfield services could
adversely affect our ability to execute our exploration and
development plans on a timely basis and within our
budget.
Our industry is cyclical, and from time to time there is a
shortage of drilling rigs, equipment, supplies and qualified
personnel. Although commodity prices weakened considerably in
the second half of 2008, creating more availability of rigs,
equipment and personnel, during periods of strong commodity
prices, the costs and delivery times of rigs, equipment and
supplies are substantially greater. If the unavailability or
high cost of drilling rigs, equipment, supplies or qualified
personnel were particularly severe in the areas where we
operate, we could be materially and adversely affected.
Competition in the oil and gas industry is intense, and
many of our competitors have resources that are greater than
ours.
We operate in a highly competitive environment for acquiring
prospects and productive properties, marketing oil and gas and
securing equipment and trained personnel. Many of our
competitors are major and large independent oil and gas
companies that possess and employ financial, technical and
personnel resources substantially greater than ours. Those
companies may be able to develop and acquire more prospects and
productive properties than our financial or personnel resources
permit. Our ability to acquire additional prospects and discover
reserves in the future will depend on our ability to evaluate
and select suitable properties and consummate transactions in a
highly competitive environment. Also, there is substantial
competition for capital available for investment in the oil and
gas industry. Larger competitors may be better able to withstand
sustained periods of unsuccessful drilling and absorb the burden
of changes in laws and regulations more easily than we can,
which would adversely affect our competitive position. We may
not be able to compete successfully in the future in acquiring
prospective reserves, developing reserves, marketing
hydrocarbons, attracting and retaining quality personnel and
raising additional capital.
Our customer base is concentrated, and the loss of our key
customers could, therefore, adversely affect our financial
results.
In 2008, Ozona Pipeline and WTG Benedum/Belvan Partners, LP
accounted for approximately 61.9% and 15.8%, respectively, of
our total oil and gas sales excluding realized commodity
derivative settlements. To the extent that Ozona Pipeline or WTG
Benedum/Belvan Partners reduces their purchases in gas or oil or
defaults on their obligations to us, we would be adversely
affected unless we were able to make comparably favorable
arrangements with other customers. These purchasers
default or non-performance could be caused by factors beyond our
control. A default could occur as a result of circumstances
relating directly to one or both of these
19
customers, or due to circumstances related to other market
participants with which the customer has a direct or indirect
relationship.
We depend on our management team and other key personnel.
Accordingly, the loss of any of these individuals could
adversely affect our business, financial condition and the
results of operations and future growth.
Our success largely depends on the skills, experience and
efforts of our management team and other key personnel. The loss
of the services of one or more members of our senior management
team or of our other employees with critical skills needed to
operate our business could have a negative effect on our
business, financial condition, results of operations and future
growth. We have entered into employment agreements with J. Ross
Craft, our President and Chief Executive Officer, Steven P.
Smart, our Executive Vice President and Chief Financial Officer
and Glenn W. Reed, our Executive Vice President
Engineering and Operations. If any of these officers or other
key personnel resign or become unable to continue in their
present roles and are not adequately replaced, our business
operations could be materially adversely affected. Our ability
to manage our growth, if any, will require us to continue to
train, motivate and manage our employees and to attract,
motivate and retain additional qualified personnel. Competition
for these types of personnel is intense, and we may not be
successful in attracting, assimilating and retaining the
personnel required to grow and operate our business profitably.
We have three affiliated stockholders who, together with
our board and management, have a 42.5% interest in our company,
whose interests may differ from your interests and who will be
able to control or substantially influence the outcome of
matters voted upon by our stockholders.
At December 31, 2008, Yorktown Energy Partners V,
L.P., Yorktown Energy Partners VI, L.P. and Yorktown Energy
Partners VII, L.P., or collectively, Yorktown, which are under
common management, beneficially owned approximately 32.5% of our
outstanding common stock in the aggregate, together with a
Yorktown representative who serves on our board of directors. In
addition, our non-Yorktown directors and management team
beneficially own or control approximately 10.0% of our common
stock outstanding. As a result of this ownership and control,
Yorktown, together with our board and management, has the
ability to control or substantially influence the vote in any
election of directors. Yorktown, together with our board and
management, also has control or substantial influence over our
decisions to enter into significant corporate transactions and,
in their capacity as our majority stockholders, these
stockholders may have the ability to effectively block any
transactions that they do not believe are in Yorktowns or
managements best interest. As a result, Yorktown, together
with our board and management, is able to control, directly or
indirectly and subject to applicable law, or substantially
influence all matters affecting us, including the following:
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any determination with respect to our business direction and
policies, including the appointment and removal of officers,
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any determinations with respect to mergers, business
combinations or dispositions of assets,
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our capital structure,
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compensation, option programs and other human resources policy
decisions,
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changes to other agreements that may adversely affect
us, and
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the payment, or nonpayment, of dividends on our common stock.
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Yorktown, together with our board and management, also may have
an interest in pursuing transactions that, in their judgment,
enhance the value of their respective equity investments in our
company, even though those transactions may involve risks to you
as a minority stockholder. In addition, circumstances could
arise under which their interests could be in conflict with the
interests of our other stockholders or you, a minority
stockholder. Also, Yorktown and their affiliates have and may in
the future make significant investments in other companies, some
of which may be competitors. Yorktown and its affiliates are not
obligated to advise us of any investment or business
opportunities of which they are aware, and they are not
restricted or prohibited from competing with us.
20
We have renounced any interest in specified business
opportunities, and certain members of our board of directors and
certain of our stockholders generally have no obligation to
offer us those opportunities.
In accordance with Delaware law, we have renounced any interest
or expectancy in any business opportunity, transaction or other
matter in which our non-employee directors and certain of our
stockholders, each referred to as a Designated Party,
participates or desires to participate in that involves any
aspect of the exploration and production business in the oil and
industry. If any such business opportunity is presented to a
Designated Person who also serves as a member of our board of
directors, the Designated Party has no obligation to communicate
or offer that opportunity to us, and the Designated Party may
pursue the opportunity as he sees fit, unless:
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it was presented to the Designated Party solely in that
persons capacity as a director of our company and with
respect to which, at the time of such presentment, no other
Designated Party has independently received notice of or
otherwise identified the business opportunity, or
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the opportunity was identified by the Designated Party solely
through the disclosure of information by or on behalf of us.
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As a result of this renunciation, our outside directors should
not be deemed to be breaching any fiduciary duty to us if they
or their affiliates or associates pursue opportunities as
described above and our future competitive position and growth
potential could be adversely affected.
We are subject to complex governmental laws and
regulations that may adversely affect the cost, manner or
feasibility of doing business.
Our operations and facilities are subject to extensive federal,
state and local laws and regulations relating to the exploration
for, and the development, production and transportation of, oil
and gas, and operating safety, and protection of the
environment, including those relating to air emissions,
wastewater discharges, land use, storage and disposal of wastes
and remediation of contaminated soil and groundwater. Future
laws or regulations, any adverse changes in the interpretation
of existing laws and regulations or our failure to comply with
existing legal requirements may harm our business, results of
operations and financial condition. We may encounter reductions
in reserves or be required to make large and unanticipated
capital expenditures to comply with governmental laws and
regulations, such as:
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price control,
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taxation,
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lease permit restrictions,
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drilling bonds and other financial responsibility requirements,
such as plug and abandonment bonds,
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spacing of wells,
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unitization and pooling of properties,
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safety precautions, and
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permitting requirements.
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Under these laws and regulations, we could be liable for:
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personal injuries,
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property and natural resource damages,
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well reclamation costs, soil and groundwater remediation
costs, and
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governmental sanctions, such as fines and penalties.
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Our operations could be significantly delayed or curtailed, and
our cost of operations could significantly increase as a result
of environmental safety and other regulatory requirements or
restrictions. We are unable to predict the ultimate cost of
compliance with these requirements or their effect on our
operations. We may be
21
unable to obtain all necessary licenses, permits, approvals and
certificates for proposed projects. Intricate and changing
environmental and other regulatory requirements may require
substantial expenditures to obtain and maintain permits. If a
project is unable to function as planned, for example, due to
costly or changing requirements or local opposition, it may
create expensive delays, extended periods of non-operation or
significant loss of value in a project. See Items 1. and
2., Business and Properties Regulation.
Changes in tax laws may adversely affect our results of
operations and cash flows.
Under current federal tax laws, we are entitled to certain
deductions relating to our operations, including deductions for
intangible drilling costs, or IDCs, and depletion deductions.
The Presidents budget for the fiscal year 2010 outlines
proposals to eliminate several oil and gas federal income tax
incentives, including deductions for IDCs and percentage
depletion allowance for oil and natural gas. It is not possible
at this time to predict how legislation or new regulations that
may be adopted to address these proposals would impact our
business, but any such future laws and regulations could
adversely our results of operations and cash flows.
Operating hazards, natural disasters or other
interruptions of our operations could result in potential
liabilities, which may not be fully covered by our
insurance.
The oil and gas business involves certain operating hazards such
as:
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well blowouts,
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cratering,
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explosions,
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uncontrollable flows of gas, oil or well fluids,
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fires,
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pollution, and
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releases of toxic gas.
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The occurrence of one of the above may result in injury, loss of
life, suspension of operations, environmental damage and
remediation
and/or
governmental investigations and penalties.
In addition, our operations in Texas are especially susceptible
to damage from natural disasters such as tornados and involve
increased risks of personal injury, property damage and
marketing interruptions. Any of these operating hazards could
cause serious injuries, fatalities or property damage, which
could expose us to liabilities. The payment of any of these
liabilities could reduce, or even eliminate, the funds available
for exploration, development, exploitation and acquisition, or
could result in a loss of our properties. Consistent with
insurance coverage generally available to the industry, our
insurance policies provide limited coverage for losses or
liabilities relating to pollution, with broader coverage for
sudden and accidental occurrences. Our insurance might be
inadequate to cover our liabilities. The insurance market in
general and the energy insurance market in particular have been
difficult markets over the past several years. Insurance costs
are expected to continue to increase over the next few years and
we may decrease coverage and retain more risk to mitigate future
cost increases. If we incur substantial liability and the
damages are not covered by insurance or are in excess of policy
limits, or if we incur liability at a time when we are not able
to obtain liability insurance, then our business, results of
operations and financial condition could be materially adversely
affected.
Our results are subject to quarterly and seasonal
fluctuations.
Our quarterly operating results have fluctuated in the past and
could be negatively impacted in the future as a result of a
number of factors, including:
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seasonal variations in oil and gas prices,
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variations in levels of production, and
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the completion of exploration and production projects.
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22
Market conditions or transportation impediments may hinder
our access to oil and gas markets or delay our
production.
Market conditions and the unavailability of satisfactory oil and
gas processing and transportation may hinder our access to oil
and gas markets or delay our production. Although currently we
control the gathering system operations for a majority of our
production in the Ozona Northeast field, we do not have such
control over the regional or downstream pipelines in Ozona
Northeast or in other areas where we operate or expect to
conduct operations. The availability of a ready market for our
oil and gas production depends on a number of factors, including
the demand for and supply of oil and gas and the proximity of
reserves to pipelines or trucking and terminal facilities. In
addition, the amount of oil and gas that can be produced and
sold is subject to curtailment in certain circumstances, such as
pipeline interruptions due to scheduled and unscheduled
maintenance, excessive pressure, ability of downstream
processing facilities to accept unprocessed gas, physical damage
to the gathering or transportation system or lack of contracted
capacity on such systems. The curtailments arising from these
and similar circumstances may last from a few days to several
months, and in many cases we are provided with limited, if any,
notice as to when these circumstances will arise and their
duration. As a result, we may not be able to sell, or may have
to transport by more expensive means, the oil and gas production
from wells or we may be required to shut in gas wells or delay
initial production until the necessary gathering and
transportation systems are available. For example, in 2008 we
reported that production in Ozona Northeast was shut-in and
curtailed due to the impact of Hurricane Ike on downstream
natural gas processing facilities and, separately, the rupture
of a third-party pipeline. Any significant curtailment in
gathering system or pipeline capacity, or significant delay in
construction of necessary gathering and transportation
facilities, could adversely affect our business, financial
condition or results of operations.
Environmental liabilities may expose us to significant
costs and liabilities.
There is inherent risk of incurring significant environmental
costs and liabilities in our oil and gas operations due to the
handling of petroleum hydrocarbons and generated wastes, the
occurrence of air emissions and water discharges from
work-related activities and the legacy of pollution from
historical industry operations and waste disposal practices. We
may incur joint and several or strict liability under these
environmental laws and regulations in connection with spills,
leaks or releases of petroleum hydrocarbons and wastes on, under
or from our properties and facilities, many of which have been
used for exploration, production or development activities for
many years, oftentimes by third parties not under our control.
Private parties, including the owners of properties upon which
we conduct drilling and production activities as well as
facilities where our petroleum hydrocarbons or wastes are taken
for reclamation or disposal, may also have the right to pursue
legal actions to enforce compliance as well as to seek damages
for non-compliance with environmental laws and regulations or
for personal injury or property damage. In addition, changes in
environmental laws and regulations occur frequently, and any
such changes that result in more stringent and costly waste
handling, storage, transport, disposal or remediation
requirements could have a material adverse effect on our
business, financial condition and results of operations. We may
not be able to recover some or any of these costs from
insurance. See Items 1. and 2., Business and
Properties Regulation.
Our growth strategy could fail or present unanticipated
problems for our business in the future, which could adversely
affect our ability to make acquisitions or realize anticipated
benefits of those acquisitions.
Our growth strategy may include acquiring oil and gas businesses
and properties. We may not be able to identify suitable
acquisition opportunities or finance and complete any particular
acquisition successfully.
Furthermore, acquisitions involve a number of risks and
challenges, including:
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diversion of managements attention,
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the need to integrate acquired operations,
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potential loss of key employees of the acquired companies,
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potential lack of operating experience in a geographic market of
the acquired business, and
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an increase in our expenses and working capital requirements.
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23
Any of these factors could adversely affect our ability to
achieve anticipated levels of cash flows from the acquired
businesses or realize other anticipated benefits of those
acquisitions.
Severe weather could have a material adverse impact on our
business.
Our business could be materially and adversely affected by
severe weather. Repercussions of severe weather conditions may
include:
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curtailment of services,
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weather-related damage to drilling rigs, resulting in suspension
of operations,
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weather-related damage to our facilities,
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inability to deliver materials to jobsites in accordance with
contract schedules, and
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loss of productivity.
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A terrorist attack or armed conflict could harm our
business.
Terrorist activities, anti-terrorist efforts and other armed
conflict involving the United States may adversely affect the
United States and global economies and could prevent us from
meeting our financial and other obligations. If any of these
events occur or escalate, the resulting political instability
and societal disruption could reduce overall demand for oil and
gas, potentially putting downward pressure on demand for our
services and causing a reduction in our revenue. Oil and gas
related facilities could be direct targets for terrorist
attacks, and our operations could be adversely impacted if
significant infrastructure or facilities we use for the
production, transportation or marketing of our oil and gas
production are destroyed or damaged. Costs for insurance and
other security may increase as a result of these threats, and
some insurance coverage may become difficult to obtain, if
available at all.
Risks
related to our financial condition
We will require additional capital to fund our future
activities. If we fail to obtain additional capital, we may not
be able to fully implement our business plan, which could lead
to a decline in reserves.
We depend on our ability to obtain financing beyond our cash
flow from operations. Historically, we have financed our
business plan and operations primarily with internally generated
cash flows, borrowings under our revolving credit facility and
issuances of common stock. We also require capital to fund our
exploration and development budget. As of December 31,
2008, approximately 52% of our total estimated proved reserves
were undeveloped. Recovery of such reserves will require
significant capital expenditures and successful drilling
operations. We will be required to meet our needs from our
internally generated cash flows, debt financings and equity
financings.
If our revenues decrease as a result of lower commodity prices,
operating difficulties, declines in reserves or for any other
reason, we may have limited ability to obtain the capital
necessary to sustain our operations at current levels. We may,
from time to time, need to seek additional financing. Our
revolving credit facility contains covenants restricting our
ability to incur additional indebtedness without lender consent.
There can be no assurance that our bank lenders will provide
this consent or as to the availability or terms of any
additional financing. If we incur additional debt, the related
risks that we now face could intensify.
Even if additional capital is needed, we may not be able to
obtain debt or equity financing on terms favorable to us, or at
all. If cash generated by operations and available under our
revolving credit facility is not sufficient to meet our capital
requirements, the failure to obtain additional financing could
result in a curtailment of our operations relating to
exploration and development of our projects, which in turn could
lead to a possible loss of properties and a decline in our gas
reserves.
Our bank lenders can limit our borrowing capabilities,
which may materially impact our operations.
At December 31, 2008, we had $43.5 million in
outstanding borrowings under our revolving credit facility. At
February 28, 2009, we had $47.4 million in long-term
debt outstanding under our revolving credit facility. The
borrowing base limitation under our revolving credit facility is
redetermined semi-annually.
24
Redeterminations are based upon information contained in an
annual engineering report prepared by an independent petroleum
engineering firm and a mid-year report prepared by our own
engineers. In addition, as is typical in the oil and gas
industry, our bank lenders have substantial flexibility to
reduce our borrowing base on the basis of subjective factors.
Upon a redetermination, we could be required to repay a portion
of our outstanding borrowings, including the total face amounts
of all outstanding letters of credit and the amount of all
unpaid reimbursement obligations, to the extent such amounts
exceed the redetermined borrowing base. We may not have
sufficient funds to make such required repayment, which could
result in a default under the terms of the revolving credit
facility and an acceleration of the loan. We intend to finance
our development, acquisition and exploration activities with
cash flow from operations, borrowings under our revolving credit
facility and other financing activities. In addition, we may
significantly alter our capitalization to make future
acquisitions or develop our properties. These changes in
capitalization may significantly increase our level of debt. If
we incur additional debt for these or other purposes, the
related risks that we now face could intensify. A higher level
of debt also increases the risk that we may default on our debt
obligations. Our ability to meet our debt obligations and to
reduce our level of debt depends on our future performance which
will be affected by general economic conditions and financial,
business and other factors. Many of these factors are beyond our
control. Our level of debt affects our operations in several
important ways, including the following:
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a portion of our cash flow from operations is used to pay
interest on borrowings,
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the covenants contained in the agreements governing our debt
limit our ability to borrow additional funds, pay dividends,
dispose of assets or issue shares of preferred stock and
otherwise may affect our flexibility in planning for, and
reacting to, changes in business conditions,
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a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital
expenditures, acquisitions or general corporate purposes,
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a leveraged financial position would make us more vulnerable to
economic downturns and could limit our ability to withstand
competitive pressures, and
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any debt that we incur under our revolving credit facility will
be at variable rates which makes us vulnerable to increases in
interest rates.
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We engage in commodity derivative transactions which
involve risks that can harm our business.
To manage our exposure to price risks in the marketing of our
oil and gas production, we enter into oil and gas price
commodity derivative agreements. While intended to reduce the
effects of volatile oil and gas prices, such transactions may
limit our potential gains and increase our potential losses if
oil and gas prices were to rise substantially over the price
established by the commodity derivative. In addition, such
transactions may expose us to the risk of loss in certain
circumstances, including instances in which our production is
less than expected, there is a widening of price differentials
between delivery points for our production and the delivery
point assumed in the commodity derivative arrangement or the
counterparties to the commodity derivative agreements fail to
perform under the contracts.
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Item 1B.
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Unresolved
Staff Comments.
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None.
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Item 3.
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Legal
Proceedings.
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We are involved in various legal and regulatory proceedings
arising in the normal course of business. We do not believe that
an adverse result in any pending legal or regulatory proceeding,
together or in the aggregate, would be material to our business,
financial condition or results of operations.
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Item 4.
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Submission
of Matters to a Vote of Security Holders.
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None.
25
PART II
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Item 5.
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Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
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Trading
market and range of common stock
Our common stock is traded on the NASDAQ Global Select Market,
or Nasdaq, in the United States under the symbol
AREX. During 2008, trading volume averaged
134,407 shares per day. The following table shows the
quarterly high and low sale prices of our common stock as
reported on Nasdaq since our initial public offering on
November 8, 2007, which refer to as the IPO.
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High
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Low
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2007
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Fourth quarter (November 8 December 31)(1)
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$
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13.64
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$
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11.68
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2008
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First quarter
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$
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16.90
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$
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9.20
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Second quarter
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28.87
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15.17
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Third quarter
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30.00
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9.92
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Fourth quarter
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14.25
|
|
|
|
5.39
|
|
|
|
|
(1) |
|
Our common stock began trading on Nasdaq on November 8,
2007. |
Holders
of record
As of February 28, 2009, there were 27 record holders of
our common stock. In many instances, a registered stockholder is
a broker or other entity holding shares in street name for one
or more customers who beneficially own the shares.
Dividends
We have not paid any cash dividends on our common stock. We do
not expect to pay any cash or other dividends in the foreseeable
future on our common stock, as we intend to reinvest cash flow
generated by operations in our business. Our revolving credit
facility currently restricts our ability to pay cash dividends
on our common stock, and we may also enter into credit
agreements or other borrowing arrangements in the future that
restrict or limit our ability to pay cash dividends on our
common stock.
26
Comparison
of cumulative return
The following graph compares the cumulative return on a $100
investment in our common stock from November 8, 2007,
through December 31, 2008, to that of the cumulative return
on a $100 investment in the Standard & Poors 500
Index and the Dow Jones Wilshire Exploration &
Production Index for the same period. In calculating the
cumulative return, reinvestment of dividends, if any, is
assumed. This graph is not soliciting material, is
not deemed filed with the SEC and is not to be incorporated by
reference in any of our filings under the Securities Act of
1933, which we refer to as the Securities Act, or the Exchange
Act, whether made before or after the date hereof and
irrespective of any general incorporation language in any such
filing.
Comparison
of Total Return from November 8, 2007 through
December 31, 2008
Among Approach Resources Inc., the Standard &
Poors 500 Index and
the Dow Jones Wilshire Exploration & Production
Index
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11/8/2007
|
|
12/31/2007
|
|
12/31/2008
|
|
|
|
Approach Resources Inc.
|
|
$
|
100.00
|
|
|
$
|
102.14
|
|
|
$
|
58.06
|
|
S&P 500
|
|
|
100.00
|
|
|
|
95.15
|
|
|
|
59.95
|
|
D J Wilshire Exploration & Production
|
|
|
100.00
|
|
|
|
101.09
|
|
|
|
59.62
|
|
27
Recent
sales of unregistered securities
We did not sell any securities during the year ended
December 31, 2008 that were not registered under the
Securities Act.
Issuer
repurchases of equity securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
(d)
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
Maximum
|
|
|
|
|
|
|
|
|
|
Shares
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Purchased as
|
|
|
Shares That
|
|
|
|
(a)
|
|
|
|
|
|
Part of
|
|
|
May Yet be
|
|
|
|
Total
|
|
|
(b)
|
|
|
Publicly
|
|
|
Purchased
|
|
|
|
Number of
|
|
|
Average
|
|
|
Announced
|
|
|
Under the
|
|
|
|
Shares
|
|
|
Price Paid
|
|
|
Plans or
|
|
|
Plans or
|
|
Period:
|
|
Purchased
|
|
|
Per Share
|
|
|
Programs
|
|
|
Programs
|
|
|
October 1, 2008 October 31, 2008
|
|
|
0
|
|
|
|
N/A
|
|
|
|
0
|
|
|
|
See Note
|
|
November 1, 2008 November 30, 2008
|
|
|
5,621
|
|
|
$
|
9.60
|
|
|
|
5,621
|
|
|
|
See Note
|
|
December 1, 2008 December 31, 2008
|
|
|
0
|
|
|
|
N/A
|
|
|
|
0
|
|
|
|
See Note
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
5,621
|
|
|
$
|
9.60
|
|
|
|
5,621
|
|
|
|
See Note
|
|
Note: We adopted the Approach Resources Inc. 2007 Stock
Incentive Plan, effective as of June 28, 2007 and amended
it effective December 31, 2008. The 2007 Stock Incentive
Plan allows us to withhold shares of common stock to pay
withholding taxes payable upon vesting of a restricted stock
grant. The number of shares of common stock available for grants
under the 2007 Stock Incentive Plan is increased by the number
of shares withheld as payment of such withholding taxes. On
November 14, 2008, we withheld 5,621 shares of common
stock as the market closing price of $9.60 per share to satisfy
the income tax withholding obligations arising upon the vesting
of 21,250 restricted shares issued to an executive officer in
March 2007 under the 2007 Stock Incentive Plan.
Securities
authorized for issuance under equity compensation
plans
The following table sets forth information regarding securities
authorized for issuance under equity compensation plans and
individual compensation arrangements as of December 31,
2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c)
|
|
|
|
(a)
|
|
|
(b)
|
|
|
Number of Securities
|
|
|
|
Number of
|
|
|
Weighted-
|
|
|
Remaining Available
|
|
|
|
Securities to be
|
|
|
Average
|
|
|
for Future Issuance
|
|
|
|
Issued Upon
|
|
|
Exercise Price
|
|
|
Under Equity
|
|
|
|
Exercise of
|
|
|
of Outstanding
|
|
|
Compensation Plans
|
|
|
|
Outstanding
|
|
|
Options,
|
|
|
(Excluding Securities
|
|
|
|
Options, Warrants
|
|
|
Warrants and
|
|
|
Reflected in Column
|
|
Plan Category:
|
|
and Rights
|
|
|
Rights
|
|
|
(a))
|
|
|
Equity compensation plans approved by stockholders
|
|
|
434,302
|
|
|
$
|
8.47
|
|
|
|
1,461,016
|
|
Equity compensation plans not approved by stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
Item 6.
|
Selected
Financial Data.
|
The following table sets forth selected financial information
for the five years ended December 31, 2008. All weighted
average shares and per share data have been adjusted for the
three-for-one stock split, and the stock issuance resulting from
the combination of Approach Oil & Gas Inc., or AOG,
under a contribution agreement effective November 14, 2007.
This information should be read in conjunction with Item 7
of this report, Managements Discussion and Analysis
of Financial Condition and Results of Operations, and our
consolidated financial statements, related notes and other
financial information included in this report.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In thousands, except per share data)
|
|
|
Operating results data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
79,869
|
|
|
$
|
39,114
|
|
|
$
|
46,672
|
|
|
$
|
43,264
|
|
|
$
|
5,682
|
|
Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,621
|
|
|
|
3,815
|
|
|
|
3,889
|
|
|
|
2,910
|
|
|
|
179
|
|
Severance and production taxes
|
|
|
4,202
|
|
|
|
1,659
|
|
|
|
1,736
|
|
|
|
1,975
|
|
|
|
407
|
|
Exploration
|
|
|
1,478
|
|
|
|
883
|
|
|
|
1,640
|
|
|
|
733
|
|
|
|
2,396
|
|
Impairment of non-producing properties
|
|
|
6,379
|
|
|
|
267
|
|
|
|
558
|
|
|
|
|
|
|
|
|
|
General and administrative
|
|
|
8,881
|
|
|
|
12,667
|
|
|
|
2,416
|
|
|
|
2,659
|
|
|
|
1,943
|
|
Depletion, depreciation and amortization
|
|
|
23,710
|
|
|
|
13,098
|
|
|
|
14,551
|
|
|
|
8,011
|
|
|
|
1,224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
52,271
|
|
|
|
32,389
|
|
|
|
24,790
|
|
|
|
16,288
|
|
|
|
6,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
27,598
|
|
|
|
6,725
|
|
|
|
21,882
|
|
|
|
26,976
|
|
|
|
(467
|
)
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of investment
|
|
|
(917
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest (expense) income, net
|
|
|
(1,269
|
)
|
|
|
(5,219
|
)
|
|
|
(3,814
|
)
|
|
|
(802
|
)
|
|
|
201
|
|
Realized gain (loss) on commodity derivatives
|
|
|
2,936
|
|
|
|
4,732
|
|
|
|
6,222
|
|
|
|
(2,925
|
)
|
|
|
|
|
Change in fair value of commodity derivatives
|
|
|
7,149
|
|
|
|
(3,637
|
)
|
|
|
8,668
|
|
|
|
(4,163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before provision (benefit) for income taxes
|
|
|
35,497
|
|
|
|
2,601
|
|
|
|
32,958
|
|
|
|
19,086
|
|
|
|
(266
|
)
|
Provision (benefit) for income taxes
|
|
|
12,111
|
|
|
|
(108
|
)
|
|
|
11,756
|
|
|
|
7,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
23,386
|
|
|
$
|
2,709
|
|
|
$
|
21,202
|
|
|
$
|
12,058
|
|
|
$
|
(266
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.13
|
|
|
$
|
0.25
|
|
|
$
|
2.26
|
|
|
$
|
1.32
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.12
|
|
|
$
|
0.24
|
|
|
$
|
2.20
|
|
|
$
|
1.32
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of cash flows data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
56,435
|
|
|
$
|
30,746
|
|
|
$
|
34,305
|
|
|
$
|
40,588
|
|
|
$
|
4,528
|
|
Investing activities
|
|
|
(100,633
|
)
|
|
|
(52,940
|
)
|
|
|
(59,384
|
)
|
|
|
(72,224
|
)
|
|
|
(26,859
|
)
|
Financing activities
|
|
|
43,696
|
|
|
|
22,062
|
|
|
|
26,771
|
|
|
|
32,199
|
|
|
|
22,474
|
|
Effect of Canadian exchange rate
|
|
|
(206
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,077
|
|
|
$
|
4,785
|
|
|
$
|
4,911
|
|
|
$
|
3,219
|
|
|
$
|
2,656
|
|
Other current assets
|
|
|
30,760
|
|
|
|
12,021
|
|
|
|
12,792
|
|
|
|
15,701
|
|
|
|
5,939
|
|
Property, equipment, net, successful efforts method
|
|
|
303,404
|
|
|
|
230,819
|
|
|
|
132,520
|
|
|
|
89,407
|
|
|
|
24,742
|
|
Other assets
|
|
|
|
|
|
|
1,101
|
|
|
|
86
|
|
|
|
89
|
|
|
|
1,565
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
338,241
|
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
$
|
108,416
|
|
|
$
|
34,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
30,775
|
|
|
$
|
22,017
|
|
|
$
|
15,421
|
|
|
$
|
32,746
|
|
|
$
|
9,827
|
|
Long-term debt
|
|
|
43,537
|
|
|
|
|
|
|
|
47,619
|
|
|
|
29,425
|
|
|
|
100
|
|
Other long-term debt liabilities
|
|
|
40,116
|
|
|
|
26,890
|
|
|
|
17,697
|
|
|
|
6,555
|
|
|
|
99
|
|
Stockholders equity
|
|
|
223,813
|
|
|
|
199,819
|
|
|
|
69,572
|
|
|
|
39,690
|
|
|
|
24,876
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
338,241
|
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
$
|
108,416
|
|
|
$
|
34,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
Item 7.
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations.
|
The following discussion is intended to assist in understanding
our results of operations and our financial condition. Our
consolidated financial statements and the accompanying notes
included elsewhere in this report contain additional information
that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These
forward-looking statements involve risks and uncertainties,
which could cause actual results to differ from those expressed.
See Cautionary Statement Regarding Forward-Looking
Statements at the beginning of this report and Risk
Factors in Item 1.A for additional discussion of some
of these factors and risks.
Overview
We are an independent energy company engaged in the exploration,
development, production and acquisition of unconventional
natural gas and oil properties in the United States and British
Columbia. We focus on tight gas sands and shale and have
assembled leasehold interests aggregating approximately
300,334 gross (199,818 net) acres as of December 31,
2008. We expect to leverage our management teams proven
track record of finding and exploiting unconventional reservoirs
through advanced completion, fracturing and drilling techniques.
As the operator of over 90% of our production and proved
reserves, we have a high degree of control over capital
expenditures and other operating matters.
We currently operate or have interests in the following areas:
West Texas
|
|
|
|
|
Ozona Northeast (Wolfcamp, Canyon Sands, Strawn and Ellenburger)
|
|
|
|
Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)
|
East Texas
|
|
|
|
|
North Bald Prairie (Cotton Valley Sands, Bossier and Cotton
Valley Lime)
|
Southwest Kentucky
|
|
|
|
|
Boomerang (New Albany Shale)
|
Northeast British Columbia
|
|
|
|
|
Montney tight gas and Doig Shale
|
Northern New Mexico
|
|
|
|
|
El Vado East (Mancos Shale)
|
Segment reporting is not applicable to us as we have a single,
company-wide management team that administers all properties as
a whole rather than by discrete operating segments. We track
only basic operational data by area. We do not maintain complete
separate financial statement information by area. We measure
financial performance as a single enterprise and not on an
area-by-area
basis.
At December 31, 2008, we owned working interests in 445
producing oil and gas wells, had estimated proved reserves of
approximately 211.1 Bcfe and were producing
28.0 MMcfe/d (based on production for the month of December
2008). Our average daily net production for 2009 (through
February) was 26.5 MMcfe/d.
As of December 31, 2008, all of our proved reserves and
production were located in Ozona Northeast and Cinco Terry in
West Texas and in North Bald Prairie in East Texas. At year end
2008, our proved reserves were 82% natural gas, 48% proved
developed and had a reserve life index of over twenty years
(based on 2008 production of 8,755 MMcfe). In addition to
our producing wells, we had identified 1,205 total drilling
locations in Ozona Northeast, Cinco Terry and North Bald Prairie
at December 31, 2008, of which 312 are proved.
Our financial results depend upon many factors, particularly the
price of oil and gas. Commodity prices are affected by changes
in market demand, which is impacted by overall economic
activity, weather, pipeline
30
capacity constraints, estimates of inventory storage levels, gas
price differentials and other factors. A factor potentially
impacting the future supply balance is the recent increase in
the United States LNG import capacity. Significant LNG capacity
increases have been announced that may result in increased price
volatility. As a result, we cannot accurately predict future oil
and gas prices, and therefore, we cannot determine what effect
increases or decreases will have on our capital program,
production volumes and future revenues. A substantial or
extended decline in oil and gas prices could have a material
adverse effect on our business, financial condition, results of
operations, quantities of oil and gas reserves that may be
economically produced and liquidity that may be accessed through
our borrowing base under our revolving credit facility and
through the capital market.
In addition to production volumes and commodity prices, finding
and developing sufficient amounts of oil and gas reserves at
economical costs are critical to our long-term success. Future
finding and development costs are subject to changes in the
industry, including the costs of acquiring, drilling and
completing our projects. We focus our efforts on increasing oil
and gas reserves and production while controlling costs at a
level that is appropriate for long-term operations. Our future
cash flow from operations will depend on our ability to manage
our overall cost structure.
Like all oil and gas production companies, we face the challenge
of natural production declines. Oil and gas production from a
given well naturally decreases over time. Additionally, our
reserves have a rapid initial decline. We attempt to overcome
this natural decline by drilling to develop and identify
additional reserves, farm-ins or other joint drilling ventures,
and by acquisitions. Our future growth will depend upon our
ability to continue to add oil and gas reserves in excess of
production at a reasonable cost. We will maintain our focus on
the costs of adding reserves through drilling and acquisitions
as well as the costs necessary to produce such reserves.
We also face the challenge of financing future acquisitions. We
believe we have adequate unused borrowing capacity under our
revolving credit facility for possible acquisitions, temporary
working capital needs and any expansion of our drilling program.
Funding for future acquisitions also may require additional
sources of financing, which may not be available.
Reduction
in capital expenditures and drilling activities
In December 2008, in response to a decline in oil, gas and NGL
prices and uncertain market conditions, we announced that we
were reducing our capital expenditure budget to
$43.8 million in 2009, compared to $100.1 million of
actual capital expenditures in 2008 (including
$10.3 million in exploration and development costs related
to the acquisition of deep rights in Ozona Northeast in July
2008). We also have reduced the number of our operating rigs
from five in June 2008 to two at February 28, 2009. We
intend to fund 2009 capital expenditures (excluding any
acquisitions) with internally-generated cash flow, with any
excess cash flow applied towards debt, working capital or
strategic acquisitions. We will continue to monitor commodity
prices and operating expenses to determine any further
adjustments to the capital budget and, unless commodity prices
strengthen, we will materially reduce our 2009 capital
expenditures and number of operated rigs. The
previously-announced reduction in capital expenditures and
drilling activities, along with any additional reductions
undertaken by the Company, could materially reduce our
production volumes and revenues from pre-2009 levels and
increase future expected costs necessary to develop existing
reserves.
Critical
accounting policies and estimates
The discussion and analysis of our financial condition and
results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with
accounting policies generally accepted in the United States. The
preparation of our consolidated financial statements requires us
to make estimates and assumptions that affect our reported
results of operations and the amount of reported assets,
liabilities and proved oil and gas reserves. Some accounting
policies involve judgments and uncertainties to such an extent
that there is reasonable likelihood that materially different
amounts could have been reported under different conditions, or
if different assumptions had been used. Actual results may
differ from the estimates and assumptions used in the
preparation of our consolidated financial statements. Described
below
31
are the most significant policies we apply in preparing our
consolidated financial statements, some of which are subject to
alternative treatments under GAAP. We also describe the most
significant estimates and assumptions we make in applying these
policies. See Note 1 to our consolidated financial
statements.
Oil
and gas activities successful efforts
Accounting for oil and gas activities is subject to special,
unique rules. We use the successful efforts method of accounting
for our oil and gas activities. The significant principles for
this method are:
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geological and geophysical evaluation costs are expensed as
incurred,
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dry holes for exploratory wells are expensed, and dry holes for
developmental wells are capitalized, and
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Capitalized costs related to proved oil and gas properties,
including wells and related equipment and facilities, are
evaluated for impairment based on an analysis of undiscounted
future net cash flows in accordance with Statement of Financial
Accounting Standards 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. If undiscounted cash flows
are insufficient to recover the net capitalized costs related to
proved properties, then we recognize an impairment charge in
income from operations equal to the difference between the net
capitalized costs related to unproved properties and their
estimated fair values based on the present value of the related
future net cash flows. We noted no impairment of our proved
properties based on our analysis for the years ended
December 31, 2008, 2007 or 2006.
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Our engineering estimates of proved oil and gas reserves
directly impact financial accounting estimates including
depletion, depreciation and amortization expense, evaluation of
impairment of properties and the calculation of plugging and
abandonment liabilities. Proved oil and gas reserves are the
estimated quantities of oil and gas that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under
period-end economic and operating conditions. The process of
estimating quantities of proved reserves is very complex,
requiring significant subjective decisions in the evaluation of
all geological, engineering and economic data for each
reservoir. The data for any reservoir may change substantially
over time as a result of changing results from operational
activity and results. Changes in commodity prices, operation
costs and techniques may also affect the overall evaluation of
reservoirs. A hypothetical 10% decline in our December 31,
2008 proved reserves volumes would have been insignificant to
depletion expense for the year ended December 31, 2008 nor
would it have resulted in an impairment of oil and gas
properties.
Our estimated proved reserves as of December 31, 2008, 2007
and 2006 were prepared by DeGolyer and MacNaughton.
Derivative
instruments and commodity derivative activities
Unrealized gains and losses, at fair value, are included on our
consolidated balance sheets as current or non-current assets or
liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our
commodity derivative contracts are recorded in earnings as they
occur and included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap
contracts based on the present value of the difference in
exchange-quoted forward price curves and contractual settlement
prices multiplied by notional quantities. We internally valued
the collar contracts using industry-standard option pricing
models and observable market inputs. We use our internal
valuations to determine the fair values of the contracts that
are reflected on our consolidated balance sheets. Realized gains
and losses are also included in other income (expense) on our
consolidated statements of operations.
We are exposed to credit losses in the event of nonperformance
by the counterparty on our commodity derivatives positions and
have considered the exposure in our internal valuations.
However, we do not anticipate nonperformance by the counterparty
over the term of the commodity derivatives positions.
Changes in the derivatives fair value are currently
recognized in the statement of operations unless specific
commodity derivative hedge accounting criteria are met. For
qualifying cash-flow commodity
32
derivatives, the gain or loss on the derivative is deferred in
accumulated other comprehensive income (loss) to the extent the
commodity derivative is effective. The ineffective portion of
the commodity derivative is recognized immediately in the
statement of operations. Gains and losses on commodity
derivative instruments included in accumulated other
comprehensive income (loss) are reclassified to oil and gas
sales revenue in the period that the related production is
delivered. Derivative contracts that do not qualify for
commodity derivative accounting treatment are recorded as
derivative assets and liabilities at fair value in the balance
sheet, and the associated unrealized gains and losses are
recorded as current income or expense in the statement of
operations.
Historically, we have not designated our derivative instruments
as cash-flow hedges. We record our open derivative instruments
at fair value on our consolidated balance sheets as either
unrealized gains or losses on commodity derivatives. We record
changes in such fair value in earnings on our consolidated
statements of operations under the caption entitled
unrealized gain (loss) on commodity derivatives.
Although we have not designated our derivative instruments as
cash-flow hedges, we use those instruments to reduce our
exposure to fluctuations in commodity prices related to our oil
and gas production. Accordingly, we record realized gains and
losses under those instruments in other revenues on our
consolidated statements of operations. For the year ended
December 31, 2008, we recognized an unrealized gain of
$7.1 million from the change in the fair value of commodity
derivatives. For the year ended December 31, 2007, we
recognized an unrealized loss of $3.6 million from the
change in the fair value of commodity derivatives. A 10%
increase in the NYMEX floating prices would have resulted in a
$1.7 million decrease in the December 31, 2008 fair
value recorded on our balance sheet, and a corresponding
decrease to the gain on commodity derivatives in our statement
of operations.
Asset
retirement obligation
Our asset retirement obligation primarily represents the
estimated present value of the amount we will incur to plug,
abandon and remediate our producing properties at the end of
their productive lives, in accordance with applicable federal,
state and local laws. We determine our asset retirement
obligation by calculating the present value of estimated cash
flows related to the liability. The retirement obligation is
recorded as a liability at its estimated present value as of the
assets inception, with an offsetting increase to proved
properties. Periodic accretion of discount of the estimated
liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions,
including current estimates of plugging and abandonment costs,
annual inflation of these costs, the productive lives of wells
and our risk-adjusted interest rate. Changes in any of these
assumptions can result in significant revisions to the estimated
asset retirement obligation.
Share-based
compensation
We measure and record compensation expense for all share-based
payment awards to employees and outside directors based on
estimated grant-date fair values. Compensation costs for awards
granted are recognized over the requisite service period based
on the grant-date fair value.
The fair value of each option granted was estimated using an
option-pricing model with the following weighted average
assumptions during the years ended December 31, 2008 and
2007. There were no options granted during the year ended
December 31, 2006.
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2008
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2007
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Expected dividends
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|
|
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Expected volatility
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64%
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|
68%
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|
Risk-free interest rate
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|
2.7%
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|
3.9%
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Expected life
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6 years
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6 years
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We have not paid out dividends historically, thus the dividend
yields are estimated at zero percent.
33
Since our shares were not publicly traded prior to our initial
public offering on November 8, 2007, we used an average of
historical volatility rates based upon other companies within
our industry. Management believes that these average historical
volatility rates are currently the best available indicator of
expected volatility.
The risk-free interest rate is the implied yield available for
zero-coupon U.S. government issues with a remaining term of
five years.
The expected lives of our options are determined based on the
term of the option using the simplified method outlined in Staff
Accounting Bulletin 110.
Assumptions are reviewed each time there is a new grant and may
be impacted by actual fluctuation in our stock price, movements
in market interest rates and option terms. The use of different
assumptions produces a different fair value for the options
granted or modified and impacts the amount of compensation
expense recognized on the consolidated statement of operations.
A 10% or 20% increase in the volatility, risk-free interest rate
or stock price would not have significantly impacted share-based
compensation expense for the year ended December 31, 2008.
Recent
accounting pronouncements
In March 2008, the Financial Accounting Standards Board, or
FASB, issued Statement of Financial Accounting Standard 161,
Disclosures about Derivative Instruments and Hedging Activities,
an amendment of FASB Statement 133, or SFAS 161.
SFAS 161 amends and expands the disclosure requirements of
FASB Statement 133 with the intent to provide users of financial
statement with an enhanced understanding of (i) how and why
an entity uses derivative instruments, (ii) how derivative
instruments and the related hedged items are accounted for under
FASB Statement 133 and its related interpretations, and
(iii) how derivative instruments and related hedged items
affect and entitys financial position, financial
performance and cash flows. SFAS 161 is effective for
financial statements issued for years and interim periods
beginning after November 15, 2008. The effect of adopting
SFAS 161 is not expected to have a significant effect on
our reported financial position or earnings.
In December 2007, FASB issued Statement of Financial Accounting
Standards 141 (revised 2007), Business Combinations, or
SFAS 141(R). SFAS 141(R), among other things,
establishes principles and requirements for how the acquirer in
a business combination (i) recognizes and measures in its
financial statements the identifiable assets acquired, the
liabilities assumed, and any noncontrolling interest in the
acquired business, (ii) recognizes and measures the
goodwill acquired in the business combination or a gain from a
bargain purchase, and (iii) determines what information to
disclose to enable users of the financial statements to evaluate
the nature and financial effects of the business combination.
SFAS 141(R) is effective for fiscal years beginning on or
after December 15, 2008, with early adoption prohibited.
This standard will change our accounting treatment for business
combinations on a prospective basis.
In December 2007, the FASB issued Statement of Financial
Accounting Standards 160, Noncontrolling Interests in
Consolidated Financial Statements, an Amendment of ARB 51,
or SFAS 160. SFAS 160 establishes accounting and
reporting standards for noncontrolling interests in a subsidiary
and for the deconsolidation of a subsidiary. Minority interests
will be recharacterized as noncontrolling interests and
classified as a component of equity. It also establishes a
single method of accounting for changes in a parents
ownership interest in a subsidiary and requires expanded
disclosures. This statement is effective for fiscal years
beginning on or after December 15, 2008, with early
adoption prohibited. The effect of adopting SFAS 160 is not
expected to have a significant effect on our reported financial
position or earnings.
Effects
of inflation
Inflation in the United States has been relatively low in recent
years and did not have a material impact on our results of
operations for the years ended December 31, 2008, 2007 or
2006. Although the impact of inflation has been insignificant in
recent years, it is still a factor in the United States economy
and may increase the cost to acquire or replace property, plant
and equipment. It may also increase the cost of labor or
34
supplies. To the extent permitted by competition, regulation and
our existing agreements, we have and will continue to pass along
increased costs to our customers in the form of higher prices.
Share-based
compensation
Our 2007 Stock Incentive Plan allows grants of stock and options
to employees and outside directors. Granting of awards may
increase our general and administrative expenses subject to the
size and timing of the grants. See Note 6 to our
consolidated financial statements.
Recent
developments in reserve reporting
On December 31, 2008, the SEC released a Final Rule,
Modernization of Oil and Gas Reporting, updating its oil
and gas reporting requirements. The new reporting requirements
will be effective for our financial statements for the year
ending December 31, 2009 and our 2009 year-end proved
reserve estimates. The new reporting requirements include
provisions that:
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Permit the use of new technologies to establish the reasonable
certainty of proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about
reserves volumes,
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Allow companies to disclose their probable and possible reserves
in SEC-filed documents (currently, SEC rules limit disclosure to
only proved reserves),
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Require companies to report the independence and qualifications
of a reserves preparer or auditor,
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Require companies to file a report when a third party is relied
upon to prepare reserves estimates or conducts a reserves
audit, and
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Require companies to report oil and gas reserves using an
average price based upon the prior
12-month
period (rather than year-end prices).
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We are currently evaluating the impact that these new reporting
requirements will have for the year ended December 31, 2009.
35
Results
of operations
Years
ended December 31, 2008 and 2007
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Year Ended
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December 31,
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2008
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2007
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Revenues (in thousands):
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Gas
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$
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58,819
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$
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33,497
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Oil
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16,413
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|
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5,062
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NGLs
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4,637
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555
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Total oil and gas sales
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79,869
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|
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39,114
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Realized gain on commodity derivatives
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2,936
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4,732
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Total oil and gas sales including derivative impact
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$
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82,805
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$
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43,846
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Production:
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Gas (MMcf)
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7,092
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4,801
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Oil (MBbls)
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|
175
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|
72
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NGLs (MBbls)
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102
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|
12
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Total (MMcfe)
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8,755
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|
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|
5,305
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Average prices:
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Gas (per Mcf)
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$
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8.29
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$
|
6.98
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Oil (per Bbl)
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93.79
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70.31
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NGLs (per Bbl)
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45.46
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46.25
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Total (per Mcfe)
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|
$
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9.12
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|
|
$
|
7.37
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Realized gain on commodity derivatives (per Mcfe)
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|
|
0.34
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|
|
|
0.89
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|
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Total per Mcfe including derivative impact
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$
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9.46
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$
|
8.26
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Costs and expenses (per Mcfe):
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Lease operating
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$
|
0.87
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|
$
|
0.72
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Severance and production taxes
|
|
|
0.48
|
|
|
|
0.31
|
|
Exploration
|
|
|
0.17
|
|
|
|
0.17
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Impairment of non-producing properties
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|
|
0.73
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0.05
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General and administrative
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|
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1.01
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|
|
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2.39
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Depletion, depreciation and amortization
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|
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2.71
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|
|
|
2.47
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Oil and gas sales. Oil and gas sales increased
$40.8 million, or 104.2%, for the year ended
December 31, 2008 to $79.9 million from
$39.1 million for the year ended December 31, 2007.
The increase in oil and gas sales principally resulted from our
increased ownership in the Ozona Northeast field as a result of
our acquisition of the Neo Canyon interest in the fourth quarter
of 2007 and increased revenue from our Cinco Terry and North
Bald Prairie fields. We now own substantially all of the working
interest in Ozona Northeast. Of the 8,755 MMcfe of
production reported for 2008, approximately 1,791 MMcfe was
attributable to the interest acquired from Neo Canyon. The
increase in oil and gas sales also resulted from continued
development of our Cinco Terry and North Bald Prairie fields.
Cinco Terry production increased by 2,097 MMcfe compared to
the prior year. Production from North Bald Prairie accounted for
447 MMcfe in production for 2008. Further, the average
price per Mcfe we received for our production increased from
$7.37 to $9.12 per Mcfe as average oil and gas prices increased
significantly between the two years. Of the $40.8 million
increase in revenues, $32.8 million was attributable to
growth in volume with the remaining $8.0 million due to oil
and gas price increases. Natural gas sales represented 73.6% of
the total oil and gas sales in 2008 compared to 85.6% in 2007,
as our Cinco Terry field has a larger component of oil and NGLs
in its production.
36
Commodity derivative activities. Realized
losses and gains from our commodity derivative activity
increased our earnings by $2.9 million and
$4.7 million for the years ended December 31, 2008 and
2007, respectively. Realized gains and losses are derived from
the relative movement of gas prices in relation to the range of
prices in our collars or the fixed notional pricing for the
respective years. The unrealized gain on commodity derivatives
was $7.1 million for 2008 and the unrealized loss on
commodity derivatives was $3.6 million for 2007. As natural
gas commodity prices increase, the fair value of the open
portion of those positions decreases. As natural gas commodity
prices decrease, the fair value of the open portion of those
positions increases. Historically, we have not designated our
derivative instruments as cash-flow hedges. We record our open
derivative instruments at fair value on our consolidated balance
sheets as either unrealized gains or losses on commodity
derivatives. We record changes in such fair value in earnings on
our consolidated statements of operations under the caption
entitled unrealized gain (loss) on commodity
derivatives.
Lease operating expense. Our lease operating
expenses, or LOE, increased $3.8 million, or 99.8%, for the
year ended December 31, 2008 to $7.6 million ($0.87
per Mcfe) from $3.8 million ($0.72 per Mcfe) for the year
ended December 31, 2007. The increase in LOE over the prior
year was primarily a result of the acquisition of the Neo Canyon
30% working interest and Strawn/Ellenburger deep rights in Ozona
Northeast. The increase in 2008 was also attributable to initial
startup costs, including compression and treating costs in Cinco
Terry and North Bald Prairie, as well as a rise in repair and
maintenance costs in Ozona Northeast. Following is a summary of
lease operating expenses (per Mcfe):
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|
|
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|
|
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2008
|
|
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2007
|
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Change
|
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% Change
|
|
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Compressor rental and repair
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$
|
0.28
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|
|
$
|
0.18
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|
|
$
|
0.10
|
|
|
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55.6
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%
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Pumpers and supervision
|
|
|
0.15
|
|
|
|
0.10
|
|
|
|
0.05
|
|
|
|
50.0
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Ad valorem taxes
|
|
|
0.14
|
|
|
|
0.18
|
|
|
|
(0.04
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)
|
|
|
(22.2
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)
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Repairs and maintenance
|
|
|
0.13
|
|
|
|
0.07
|
|
|
|
0.06
|
|
|
|
85.7
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Water hauling, insurance and other
|
|
|
0.13
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|
|
|
0.12
|
|
|
|
0.01
|
|
|
|
8.3
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|
Workovers
|
|
|
0.04
|
|
|
|
0.07
|
|
|
|
(0.03
|
)
|
|
|
(42.9
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total
|
|
$
|
0.87
|
|
|
$
|
0.72
|
|
|
$
|
0.15
|
|
|
|
20.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and production taxes. Our production
taxes increased $2.5 million, or 153.3%, for the year ended
December 31, 2008 to $4.2 million from
$1.7 million for the year ended December 31, 2007. The
increase in production taxes was a function of the increase in
oil and gas sales between the two periods. Severance and
productions taxes amounted to approximately 5.3% and 4.2% of oil
and gas sales for the respective years. The increase in the
severance and production taxes as a percentage of oil and gas
sales is due to higher severance tax rates for NGL revenues from
Cinco Terry and higher estimated taxes after abatements for
newer wells in Ozona Northeast and Cinco Terry.
Exploration. We recorded $1.5 million of
exploration expense for the year ended December 31, 2008,
compared to $883,000 for the year ended December 31, 2007.
Exploration expense for the 2008 period resulted from one dry
hole drilled in Ozona Northeast and $965,000 of lease extensions
in Ozona Northeast. We incur these costs to maintain our
leasehold positions and accordingly, we expense them as
incurred. Exploration expense for the 2007 period resulted from
the drilling of two dry holes in our Boomerang project and Cinco
Terry project.
Impairment of oil and gas properties. In
accordance with SFAS 144, we review our long-lived assets
to be held and used, including proved and unproved oil and gas
properties accounted for under the successful efforts method of
accounting. As a result of this review of the recoverability of
the carrying value of our assets, we recorded an impairment of
oil and gas properties of $6.4 million and $267,000 in 2008
and 2007, respectively. The 2008 impairment resulted from a
non-cash write-off of $2.3 million of drilling costs
incurred for three test wells in our Boomerang project and $4.1
related to the drilling and completion of three wells in our
Northeast British Columbia project. The 2007 impairment resulted
from the abandonment of an expiring leasehold position in Ozona
Northeast covering 2,282 acres.
37
General and administrative. Our general and
administrative expenses decreased $3.8 million, or 29.9%,
to $8.9 million ($1.01 per Mcfe) for the year ended
December 31, 2008 from $12.7 million ($2.39 per Mcfe)
for the year ended December 31, 2007. General and
administrative expenses for 2007 included $4.6 million in
non-cash, share-based compensation (of which $3.9 million
was related to the IPO), $2.4 million in cash incentive
compensation to cover out-of-pocket taxes related to IPO stock
awards, $1.0 million of cash incentive compensation related
to the IPO and $0.7 million in cash incentive compensation
to cover out-of-pocket taxes related to managements
exchange of common stock in 2007 to repay full recourse
management notes before the IPO. Partially offsetting the higher
expenses in 2007 was an increase in general and administrative
expense in 2008 attributable to increased salaries and benefits
of $2.0 million related to an increase in staff,
professional fees of $900,000, share-based compensation of
$1.1 million and cash incentive compensation of $967,000.
Additionally, the 2007 period includes a severance obligation of
$350,000 related to a former employee. Following is a summary of
general and administrative expenses (in millions and per Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
%
|
|
|
|
$MM
|
|
|
Mcfe
|
|
|
$MM
|
|
|
Mcfe
|
|
|
$MM
|
|
|
Mcfe
|
|
|
Change
|
|
|
Salaries and benefits
|
|
$
|
4.8
|
|
|
$
|
0.55
|
|
|
$
|
2.8
|
|
|
$
|
0.54
|
|
|
$
|
2.0
|
|
|
$
|
0.01
|
|
|
|
1.8
|
%
|
Professional fees
|
|
|
1.4
|
|
|
|
0.16
|
|
|
|
0.5
|
|
|
|
0.10
|
|
|
|
0.9
|
|
|
|
0.06
|
|
|
|
60.0
|
|
Share-based compensation
|
|
|
1.1
|
|
|
|
0.13
|
|
|
|
4.6
|
|
|
|
0.87
|
|
|
|
(3.5
|
)
|
|
|
(0.74
|
)
|
|
|
(85.1
|
)
|
Cash incentive compensation
|
|
|
1.0
|
|
|
|
0.11
|
|
|
|
4.1
|
|
|
|
0.77
|
|
|
|
(3.1
|
)
|
|
|
(0.66
|
)
|
|
|
(85.7
|
)
|
Other
|
|
|
0.6
|
|
|
|
0.06
|
|
|
|
0.7
|
|
|
|
0.11
|
|
|
|
(0.1
|
)
|
|
|
(0.05
|
)
|
|
|
(45.5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8.9
|
|
|
$
|
1.01
|
|
|
$
|
12.7
|
|
|
$
|
2.39
|
|
|
$
|
(3.8
|
)
|
|
$
|
(1.38
|
)
|
|
|
(57.7
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization, or
DD&A. Our DD&A expense increased
$10.6 million, or 81%, to $23.7 million for the year
ended December 31, 2008 from $13.1 million for the
year ended December 31, 2007. Our DD&A expense per
Mcfe increased by $0.24, or 9.7%, to $2.71 per Mcfe for the year
ended December 31, 2008, compared to $2.47 per Mcfe for the
year ended December 31, 2007. The increase in DD&A was
primarily attributable to increased production and higher
capital costs, partially offset by an increase in our estimated
proved reserves at December 31, 2008. The higher DD&A
expense per Mcfe was primarily attributable to higher capital
costs incurred in North Bald Prairie and reserve revisions in
Ozona Northeast at December 31, 2007. In North Bald
Prairie, we paid capital costs attributable to the 50% working
interest owned by our working interest partner pursuant to our
carry and earning agreement on the first five wells drilled.
Interest expense, net. Our interest expense
decreased $4.0 million, or 75.7%, to $1.3 million for
the year ended December 31, 2008 from $5.2 million for
the year ended December 31, 2007. This decrease was
substantially the result of our lower average debt level and
lower interest rates in 2008. Additionally, interest expense for
the year ended December 31, 2007 included $1.5 million
related to the beneficial conversion feature of our convertible
notes and $548,000 relating to accrued interest on the
convertible notes.
Income taxes. Our provision for income taxes
increased to $12.1 million for the year ended
December 31, 2008, from a benefit of $108,000 for the year
ended December 31, 2007. The increase in income tax expense
was due to the increase in our income before income taxes. Our
effective income tax rate for the year ended December 31,
2008 was 34.1%, compared with a benefit of 4.2% for the year
ended December 31, 2007. The tax benefit for the year ended
December 31, 2007 related to the release of a valuation
allowance on net operating loss carryovers generated by AOG
before the combination of AOG and Approach under the
Contribution Agreement on November 14, 2007.
38
Years
ended December 31, 2007 and 2006
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
Gas
|
|
$
|
33,497
|
|
|
$
|
41,851
|
|
Oil
|
|
|
5,617
|
|
|
|
4,821
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales
|
|
$
|
39,114
|
|
|
$
|
46,672
|
|
Realized gain on commodity derivatives
|
|
|
4,732
|
|
|
|
6,222
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales including derivative impact
|
|
|
43,846
|
|
|
|
52,894
|
|
Production:
|
|
|
|
|
|
|
|
|
Gas (MMcf)
|
|
|
4,801
|
|
|
|
6,282
|
|
Oil (MBbls)
|
|
|
84
|
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
5,305
|
|
|
|
6,744
|
|
Average prices:
|
|
|
|
|
|
|
|
|
Gas (per Mcf)
|
|
$
|
6.98
|
|
|
$
|
6.66
|
|
Oil (per Bbl)
|
|
|
66.87
|
|
|
|
62.65
|
|
|
|
|
|
|
|
|
|
|
Total (per Mcfe)
|
|
$
|
7.37
|
|
|
$
|
6.92
|
|
Realized gain on commodity derivatives (per Mcfe)
|
|
|
0.89
|
|
|
|
0.92
|
|
|
|
|
|
|
|
|
|
|
Total per Mcfe including derivative impact
|
|
$
|
8.26
|
|
|
$
|
7.84
|
|
Costs and expenses (per Mcfe):
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
0.72
|
|
|
$
|
0.58
|
|
Severance and production taxes
|
|
|
0.31
|
|
|
|
0.26
|
|
Exploration
|
|
|
0.17
|
|
|
|
0.24
|
|
Impairment of non-producing properties
|
|
|
0.05
|
|
|
|
0.08
|
|
General and administrative
|
|
|
2.39
|
|
|
|
0.36
|
|
Depletion, depreciation and amortization
|
|
|
2.47
|
|
|
|
2.16
|
|
Oil and gas sales. Oil and gas sales decreased
$7.6 million, or 16.2%, for the year ended
December 31, 2007 to $39.1 million from
$46.7 million for the year ended December 31, 2006.
The decrease in sales principally resulted from a 21.3% decrease
in production, as we drilled and completed 51 gross (46
net) wells in 2007 compared to the 81 gross (53.3 net)
wells drilled and completed in 2006. The effects of decreased
production were partially offset by an increase in price. The
average price before the effect of commodity derivatives
increased $0.45 per Mcfe, or 6.5%, from $6.92 per Mcfe in 2006
to $7.37 per Mcfe in 2007. Gas sales represented 85.6% of the
total oil and gas sales in 2007 compared to 89.7% in 2006.
Commodity derivative activities. Realized
gains from our commodity derivative activity increased our
earnings $4.7 million and $6.2 million for the years
ended December 31, 2007 and 2006, respectively. The change
in fair value of commodity derivatives was a $3.6 million
decrease for the year ended December 31, 2007 and an
$8.7 million increase for the year ended December 31,
2006. During the years ended December 31, 2007 and 2006, we
used gas swaps to mitigate commodity price risk. The general
improvement in underlying commodity prices caused the decrease
in realized gains in 2007 compared to 2006. During 2007 and
2006, commodity prices tended to be lower than the notional
prices specified in our swap agreements, which resulted in a
gain to us. Additionally, we entered into a mix of swaps and
collars in 2007, which resulted in less volatility to the
results of operations.
Lease operating expense. Our lease operating
expenses, or LOE, decreased $74,000, or 1.9%, for the year ended
December 31, 2007 to $3.8 million from
$3.9 million for the year ended December 31, 2006. The
primary factor in the slight decrease in LOE was the release in
mid-2006 of one of our seven rented
39
compressors and an amine unit, which was partially offset by
higher ad valorem taxes in the year ended December 31, 2007.
Severance and production taxes. Our production
taxes decreased $77,000, or 4.4%, for the year ended
December 31, 2007 to $1.7 million from
$1.7 million for the year ended December 31, 2006. The
decrease in production taxes is a function of decreased oil and
gas revenues that were more than offset by refunds received in
2006 applicable to prior years. Severance and production taxes
were 4.2% and 3.7% as a percentage of oil and gas sales for the
years ended December 31, 2007 and December 31, 2006,
respectively. Our natural gas production from the Ozona
Northeast field is afforded a severance tax rate lower than the
normal rate (7.5%). However, we are required to file abatement
requests with the State of Texas to receive the lower rate.
Until the abatement requests are approved, we are required to
pay the normal rate.
Exploration and impairment of non-producing
properties. Our exploration costs decreased
$757,000 to $883,000 for the year ended December 31, 2007
from $1.6 million for the year ended December 31,
2006. The 2007 period included dry hole costs of $623,000 from a
well in our Boomerang prospect and $263,000 from a well in our
Cinco Terry project. The 2006 period included dry hole costs of
$1.3 million related to two wells drilled on a prospect in
Pecos County, Texas, $195,000 from one well in Ozona Northeast
and $165,000 from a well in our Boomerang prospect.
Our impairment of non-producing properties of $267,000 and
$558,000 in 2007 and 2006, respectively, arose from the
abandonment of a leasehold position in Ozona Northeast in 2007
and the abandonment of our leasehold position in Pecos County in
2006. As a result of the abandonment in Pecos County, we no
longer anticipate incurring any future costs related to these
leaseholds.
General and administrative. Our general and
administrative expenses increased $10.3 million, or 424.3%,
to $12.7 million for the year ended December 31, 2007
from $2.4 million for the year ended December 31,
2006. General and administrative expenses for 2007 included
$4.6 million in non-cash, share-based compensation (of
which $3.9 million was related to the IPO),
$2.4 million in cash incentive compensation to cover
out-of-pocket taxes related to IPO stock awards,
$1.0 million of cash incentive compensation related to the
IPO and $0.7 million in cash incentive compensation to
cover out-of-pocket taxes related to managements exchange
of common stock in 2007 to repay full recourse management notes
before the IPO. General and administrative expenses for 2007
also increased over the prior year as a result of higher
professional, staffing and public company expenses.
Depletion, depreciation and amortization, or
DD&A. Our DD&A expense decreased
$1.5 million, or 10.0% to $13.1 million for the year
ended December 31, 2007 from $14.6 million for the
year ended December 31, 2006. This decrease was primarily
attributable to decreased production partially offset by
increased oil and gas property costs in 2007. Our DD&A
expense per Mcfe produced increased by $0.31, or 14.4%, to $2.47
per Mcfe for the year ended December 31, 2007, as compared
to $2.16 per Mcfe for the year ended December 31, 2006.
Interest expense, net. Our interest expense
increased $1.4 million, or 36.8%, to $5.2 million for
the year ended December 31, 2007 from $3.8 million for
the year ended December 31, 2006. Included in interest
expense for the year ended December 31, 2007 were
$1.5 million related to the beneficial conversion feature
of our convertible notes and $548,000 relating to accrued
interest on the convertible notes. Additionally, we had
increased borrowings between the two periods to fund our
development of the Ozona Northeast field. These increases in
interest expense were partially offset by lower interest rates
in the 2007 period.
Income taxes. Income taxes decreased
$11.9 million, or 100.9%, to a benefit of $108,000 for the
year ended December 31, 2007 from a provision of
$11.8 million for the year ended December 31, 2006.
The effective tax rate was a benefit of 4.2% and an expense of
35.7% for the years ended December 31, 2007 and
December 31, 2006, respectively. Income taxes decreased
consistent with our income before tax and the realization of a
$2.8 million tax benefit related to the release of a
valuation allowance on net operating loss carryovers generated
by AOG before the combination of AOG and Approach under the
contribution agreement on November 14, 2007.
40
Liquidity
and capital resources
We generally will rely on cash generated from operations,
borrowings under our revolving credit facility and, to the
extent that credit and capital market conditions will allow,
future public equity and debt offerings to satisfy our liquidity
needs. Our ability to fund planned capital expenditures and to
make acquisitions depends upon our future operating performance,
availability of borrowings under our revolving credit facility,
and more broadly, on the availability of equity and debt
financing, which is affected by prevailing economic conditions
in our industry and financial, business and other factors, some
of which are beyond our control. Given the current conditions of
credit and capital markets, we cannot predict whether additional
liquidity from debt or equity financings beyond our revolving
credit facility will be available on acceptable terms, or at
all, in the foreseeable future.
Our cash flow from operations is driven by commodity prices and
production volumes and the effect of commodity derivatives.
Prices for oil and gas are affected by national and
international economic and political environments, national and
global supply and demand for hydrocarbons, seasonal influences
of weather and other factors beyond our control. Our working
capital is significantly influenced by changes in commodity
prices and significant declines in prices will cause a decrease
in our exploration and development expenditures and production
volumes. Cash flows from operations are primarily used to fund
exploration and development of our mineral interests.
We intend to fund 2009 capital expenditures (excluding any
acquisitions) with internally generated cash flow, with any
excess cash flow applied towards debt, working capital or
strategic acquisitions. We will continue to monitor commodity
prices and operating expenses to determine any further
adjustments to the capital budget. Unless commodity prices
strengthen, we will further reduce our expected 2009 capital
expenditures from our previously-announced capital budget of
$43.8 million, which reduction could be substantial. A
further reduction in capital expenditures could materially
reduce our production volumes and revenues from pre-2009 levels
and increase future expected costs necessary to develop existing
reserves.
For the year ended December 31, 2008, our primary sources
of cash were from financing and operating activities.
Approximately $43.5 million from borrowings (net of
payments) under our revolving credit facility and $56.4 cash
from operations were used to fund our drilling program and the
acquisition of a 95% working interest below the top of the
Strawn formation and rights to 75 miles of gathering system
in the Ozona Northeast field.
Our primary sources of cash in 2007 were from financing and
operating activities. Approximately $64.3 million from
borrowings under our revolving credit facility,
$72.4 million from the issuance of common stock,
$20.0 million from proceeds from convertible notes and
$30.7 million cash from operations were used to fund our
drilling activities, repay our revolving credit facility and
purchase 2,021,148 shares of our common stock from the
selling stockholder in our IPO.
For the year ended December 31, 2006, our primary sources
of cash were from financing and operating activities.
Approximately $18.2 million from borrowings (net of
payments) under our revolving credit facility, $6.5 million
from the issuance of common stock, $3.5 million from a loan
from one of our stockholders and $34.3 cash from operations were
used to fund our $59.4 million drilling program, the
acquisition of another working interest in the Ozona Northeast
field and $1.3 million to repurchase shares and cancel
stock options.
Our cash flow from operations is driven by commodity prices and
production volumes. Prices for oil and gas are driven by
seasonal influences of weather, national and international
economic and political environments and, increasingly, from
heightened demand for hydrocarbons from emerging nations,
particularly China and India. Our working capital is
significantly influenced by changes in commodity prices and
significant declines in prices could decrease our exploration
and development expenditures. Cash flows from operations were
primarily used to fund exploration and development of our
mineral interests. In comparing 2008 and 2007, our cash flows
from operations increased in 2008 due mostly to higher oil and
gas sales partially offset by an increase in most operating
expense categories and a decrease in working capital components
during the year ended December 31, 2008. In comparing 2007
and 2006, our cash flows from operations decreased in
41
2007 due mostly to lower oil and gas sales and higher general
and administrative expenses during the year ended
December 31, 2007.
The following table summarizes our sources and uses of funds for
the periods noted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
Cash flows provided by operating activities
|
|
$
|
56,435
|
|
|
$
|
30,746
|
|
|
$
|
34,305
|
|
Cash flows used in investing activities
|
|
|
(100,633
|
)
|
|
|
(52,940
|
)
|
|
|
(59,384
|
)
|
Cash flows provided by financing activities
|
|
|
43,696
|
|
|
|
22,062
|
|
|
|
26,771
|
|
Effect of Canadian exchange rate
|
|
|
(206
|
)
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
$
|
(708
|
)
|
|
$
|
(126
|
)
|
|
$
|
1,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
activities
For the year ended December 31, 2008, our cash flow from
operations, borrowings under our revolving credit facility and
available cash were used for drilling activities. The
$56.4 million in cash flow generated during 2008 period
increased by $25.7 million from 2007 due primarily to an
increase in oil and gas sales and a decrease in general and
administrative expenses. Partially offsetting the increase in
oil and gas sales and decrease in general administrative
expenses was a reduction in working capital and an increase in
LOE and production taxes in the 2008 period compared to the 2007
period.
For the year ended December 31, 2007, our cash flow from
operations was used for drilling activities. The
$30.7 million in cash flow generated during 2007 decreased
$3.6 million from 2006 due mostly to lower oil and gas
sales and higher general and administrative expenses in the 2007
period.
Investing
activities
The majority of our cash flows used in investing activities for
the years ended 2008, 2007 and 2006 have been used for the
continued development of the Ozona Northeast, Cinco Terry and
North Bald Prairie fields. The following is a summary of capital
expenditures by prospect (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Exploration and development costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
$
|
31,362
|
|
|
$
|
27,986
|
|
|
$
|
52,303
|
|
Ozona Northeast deep rights acquisition
|
|
|
10,346
|
|
|
|
|
|
|
|
|
|
Cinco Terry
|
|
|
32,363
|
|
|
|
10,586
|
|
|
|
3,176
|
|
North Bald Prairie
|
|
|
15,871
|
|
|
|
4,974
|
|
|
|
|
|
El Vado East
|
|
|
176
|
|
|
|
|
|
|
|
|
|
Boomerang
|
|
|
290
|
|
|
|
2,496
|
|
|
|
|
|
Inventory
|
|
|
2,365
|
|
|
|
|
|
|
|
|
|
Northeast British Columbia
|
|
|
2,993
|
|
|
|
1,235
|
|
|
|
|
|
Lease acquisition, geological, geophysical and other(1)
|
|
|
4,323
|
|
|
|
4,920
|
|
|
|
3,873
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
100,089
|
|
|
$
|
52,197
|
|
|
$
|
59,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $1.9 million of leasehold acquisitions related to
Ozona Northeast and $2.0 million of leasehold acquisitions
related to Cinco Terry during the year ended December 31,
2008. Includes $3.0 million for undeveloped leaseholds in
our Northeast British Columbia prospect and $2.5 million
for undeveloped leaseholds in our El Vado East prospect during
the year ended December 31, 2007. Includes
$3.5 million that was invested in undeveloped leaseholds in
our Boomerang prospect for the year ended December 31, 2006. |
42
In December 2008, we announced an exploratory and development
budget of $43.8 million for 2009. We will materially reduce
this budget unless commodity prices strengthen. Our budgets are
established based on expected volumes to be produced and
commodity prices.
Financing
activities
We borrowed $121.7 million under our revolving credit
facility in 2008 compared to $64.3 million in 2007. We
repaid a total of $78.2 million and $111.9 million of
amounts outstanding under our revolving credit facility for the
years ended December 31, 2008 and 2007, respectively.
Additionally, we borrowed $20 million in 2007 by issuing
convertible notes. These notes were converted to outstanding
shares of our common stock in connection with our IPO in
November 2007. For 2006, we borrowed $119.5 million under
our revolving credit facility, repaid $101.4 million under
the facility and spent $1.3 million to purchase common
stock and related options from a former employee.
In 2007, and in connection with our IPO and exercise by the
underwriters of their overallotment option, we sold
6,598,572 shares of our common stock in November 2007 at
$12.00 per share. The gross proceeds of our IPO and
over-allotment option were approximately $79.2 million,
which resulted in net proceeds to the Company of
$73.6 million after deducting underwriter discounts and
commissions of approximately $5.6 million. The aggregate
net proceeds of approximately $73.6 million received by the
Company were used as follows (in millions):
|
|
|
|
|
Repayment of revolving credit facility
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|
$
|
51.1
|
|
Repurchase of stock held by selling stockholder
|
|
$
|
22.5
|
|
In 2006, we borrowed $119.5 million under our revolving
credit facility and repaid $101.4 million. Additionally in
2006, we sold approximately $6.5 million of common stock
and spent $1.3 million to purchase common stock and related
options from a former employee. These net proceeds were
primarily used to fund a portion of our drilling program in
Ozona Northeast and Cinco Terry and the acquisition of our
Boomerang prospect.
Our goal is to actively manage our borrowings to help us
maintain the flexibility to expand and invest, and to avoid the
problems associated with highly leveraged companies of large
interest costs and possible debt reductions restricting ongoing
operations.
We believe that cash flow from operations will finance
substantially all of our anticipated drilling, exploration and
capital needs in 2009. We may use our revolving credit facility
for possible acquisitions and temporary working capital needs.
We also may determine to access the public equity or debt market
for potential acquisitions, working capital or other liquidity
needs, if such financing is available on acceptable terms. Given
the current conditions of credit and capital markets, we cannot
predict whether additional liquidity from debt or equity
financings beyond our credit facility will be available on
acceptable terms, or at all, in the foreseeable future.
Future
capital expenditures for 2009
We intend to fund 2009 capital expenditures (excluding any
acquisitions) with internally generated cash flow, with any
excess cash flow applied towards debt, working capital or
strategic acquisitions. The capital expenditure budget is
subject to change depending upon a number of factors, including
economic and industry conditions at the time of drilling,
prevailing and anticipated prices for oil and gas, the results
of our development and exploration efforts, the availability of
sufficient capital resources to us and other participants for
drilling prospects, our financial results, the availability of
leases on reasonable terms and our ability to obtain permits for
the drilling locations. In December 2008, we announced an
exploratory and development budget of $43.8 million for
2009. We will continue to monitor commodity prices and operating
expenses to determine any further adjustments to the capital
budget, and will materially reduce our 2009 budget unless
commodity prices strengthen. A further reduction in capital
expenditures would materially reduce our production volumes and
revenues from pre-2009 levels and increase future development
costs for our existing reserves.
43
Credit
facility
We have a $200.0 million revolving credit facility with a
borrowing base set at $100.0 million. The borrowing base is
redetermined semi-annually on or before each April 1 and October
1 based on our oil and gas reserves. We or the lenders can each
request one additional borrowing base redetermination each
calendar year. Our next scheduled redetermination date is
April 1, 2009.
The maturity date under our revolving credit facility is
July 31, 2010. Borrowings bear interest based on the agent
banks prime rate, or the sum of the LIBOR plus an
applicable margin ranging from 1.25% to 2.00% based on the
borrowings outstanding compared to the borrowing base. In
addition, we pay an annual commitment of 0.375% of non-used
borrowings available under our revolving credit facility.
We had outstanding borrowings of $43.5 million under our
revolving credit facility at December 31, 2008. The
interest rate applicable to our outstanding borrowings was 3.3%
and 6.6% as of December 31, 2008 and December 31,
2007, respectively. We also have outstanding unused letters of
credit under our revolving credit facility totaling $400,000 at
December 31, 2008, which reduce amounts available for
borrowing under our revolving credit facility.
The agent bank, other participating banks and their respective
commitment percentages are as follows: The Frost National Bank
(agent bank) 30%, JPMorgan Chase Bank,
NA 30%, Fortis Capital Corp. 20% and
KeyBank National Association 20%.
Our revolving credit facility contains financial and other
covenants that:
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|
|
|
|
require maintenance of a minimum modified ratio of current
assets to current liabilities of 1.0 to 1.0,
|
|
|
|
require maintenance of a debt to EBITDAX ratio of 3.5 to 1.0 or
less, and
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|
restrict cash dividends and other restricted payments,
transactions with affiliates, incurrence of other debt,
consolidations and mergers, the level of operating leases,
assets sales, investments in other entities and liens on
properties.
|
We were in compliance with the covenants under our revolving
credit facility at December 31, 2008.
Loans under our revolving credit facility are secured by first
priority liens on substantially all of our West Texas assets and
equity interests in our subsidiaries.
Current credit market conditions have resulted in lenders
significantly tightening their lending practices. To date we
have experienced no disruptions in our ability to access our
revolving credit facility. However, our lenders have substantial
ability to reduce our borrowing base on the basis of subjective
factors, including the loan collateral value that each lender,
in its discretion and using the methodology, assumptions and
discount rates as such lender customarily uses in evaluating oil
and gas properties, assigns to our properties.
We cannot predict with certainty the impact to us of any further
disruption in the credit environment or guarantee that the
lenders under our revolving credit facility will not decrease
our borrowing base in the future. If our borrowing base was
decreased below our total outstanding borrowings, resulting in a
borrowing base deficiency, then we would be required under the
credit agreement, within 15 days after notice from the
agent bank, to (i) pledge additional collateral to cure the
borrowing base deficiency, (ii) prepay the borrowing base
deficiency in full, or (iii) commit to prepay the borrowing
base deficiency in six equal monthly installments, with the
first installment being due within 30 days after receipt of
notice from the agent bank. There is no guarantee that, in the
event of such a borrowing base deficiency, we would be able to
timely cure the deficiency.
At February 28, 2009, we had $47.4 million outstanding
under our revolving credit facility.
Contractual
commitments
Our contractual commitments consist of long-term debt, daywork
drilling contracts, operating lease obligations, asset
retirement obligations and employment agreements with executive
officers.
44
Our long-term debt is composed of borrowings under our revolving
credit facility. See Managements Discussion and
Analysis of Financial Condition and Results of
Operations Credit Facility and
Note 5 Line of Credit for a discussion of our
revolving credit facility.
We periodically enter into contractual arrangements under which
we are committed to expend funds to drill wells in the future,
including agreements to secure drilling rig services, which
require us to make future minimum payments to the rig operators.
We record drilling commitments in the periods in which well
capital is incurred or rig services are provided. Our commitment
under the drilling contracts is $2.8 million at
December 31, 2008.
In April 2007, we signed a five-year lease for approximately
13,000 square feet of new office space in Fort Worth,
Texas. In August 2008, we expanded our office space under an
amendment to the lease to approximately 18,000 square feet.
In January 2009, we began rent payments of approximately $30,000
per month, including common area expenses. We have a lease for
our prior space in Fort Worth that expires in May 2009. Our
remaining obligation under this lease is approximately $10,000
per month until expiration in May 2009. At December 31,
2008, we had signed subleases for all of our prior office space.
We have outstanding employment agreements with executive
officers that contain automatic renewal provisions providing
that such agreements may be automatically renewed for successive
terms of one year unless employment is terminated at the end of
the term by written notice given to the employee not less than
60 days prior to the end of such term. Our maximum
commitment under the employment agreements, which would apply if
the employees covered by these agreements were all terminated
without cause, was approximately $1.1 million at
December 31, 2008.
The following table summarizes these commitments as of
December 31, 2008 (in thousands):
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|
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|
|
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|
|
|
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Less Than
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|
|
|
|
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More Than
|
|
Contractual Obligations
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|
Total
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1 Year
|
|
|
1-3 Years
|
|
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3-5 Years
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5 Years
|
|
|
Long-term debt(1)
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$
|
43,537
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|
|
$
|
|
|
|
$
|
43,537
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|
|
$
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|
|
|
$
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Daywork drilling contracts(2)
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2,790
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|
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|
2,790
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|
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|
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Operating lease obligations(3)
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1,531
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|
|
|
428
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|
|
|
779
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|
|
|
324
|
|
|
|
|
|
Asset retirement obligations(4)
|
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4,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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4,225
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Employment agreements with executive officers
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1,100
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1,100
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Total
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$
|
53,183
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|
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$
|
4,318
|
|
|
$
|
44,316
|
|
|
$
|
324
|
|
|
$
|
4,225
|
|
|
|
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|
|
|
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(1) |
|
See Note 5 Line of Credit to our consolidated
financial statements for a discussion of our revolving credit
facility. |
|
(2) |
|
Daywork drilling contracts related to two drilling rigs
contracted through March 31,2008. |
|
(3) |
|
Operating lease obligations are for office space. We will
receive $49,000 for office space that has been subleased from
January 2009 through May 2009. |
|
(4) |
|
See Note 1 Summary of Significant Accounting
Policies to our consolidated financial statements for a
discussion of our asset retirement obligations. |
Off-balance
sheet arrangements
From time to time, we enter into off-balance sheet arrangements
and transactions that can give rise to off-balance sheet
obligations. As of December 31, 2008, the off-balance sheet
arrangements and transactions that we have entered into include
undrawn letters of credit, operating lease agreements and gas
transportation commitments. We do not believe that these
arrangements are reasonably likely to materially affect our
liquidity or availability of, or requirements for, capital
resources.
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Item 7A.
|
Quantitative
and Qualitative Disclosures About Market Risk.
|
Some of the information below contains forward-looking
statements. The primary objective of the following information
is to provide forward-looking quantitative and qualitative
information about our potential exposure to
45
market risks. The term market risk refers to the
risk of loss arising from adverse changes in oil and gas prices,
and other related factors. The disclosure is not meant to be a
precise indicator of expected future losses, but rather an
indicator of reasonably possible losses. This forward-looking
information provides an indicator of how we view and manage our
ongoing market risk exposures. Our market risk sensitive
instruments were entered into for commodity derivative and
investment purposes, not for trading purposes.
Commodity
price risk
Given the current economic outlook, we expect commodity prices
to remain volatile. Even modest decreases in commodity prices
can materially affect our revenues and cash flow. In addition,
if commodity prices remain suppressed for a significant amount
of time, we could be required under successful efforts
accounting rules to perform a non-cash write down of our oil and
gas properties.
We enter into financial swaps and collars to mitigate portions
of the risk of market price fluctuations. We do not designate
such instruments as cash flow hedges. Accordingly, we record
open commodity derivative positions on our consolidated balance
sheets at fair value and recognize changes in such fair values
as income (expense) on our consolidated statements of operations
as they occur.
At December 31, 2008, we have the following commodity
derivative positions outstanding:
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Volume (MMBtu)
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$/MMBtu
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Period
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Monthly
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Total
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Floor
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Ceiling
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Fixed
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NYMEX Henry Hub
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Costless collars 2009
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180,000
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2,160,000
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$
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7.50
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$
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10.50
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Costless collars 2009
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130,000
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1,560,000
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$
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8.50
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$
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11.70
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WAHA differential
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Fixed price swaps 2009
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200,000
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2,400,000
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(0.61
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)
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At December 31, 2008 and December 31, 2007, the fair
value of our open derivative contracts was an asset of
approximately $8.0 million and $868,000, respectively.
J.P. Morgan Ventures Energy Corporation is currently the only
counterparty to our commodity derivatives positions. We are
exposed to credit losses in the event of nonperformance by the
counterparty on our commodity derivatives positions. However, we
do not anticipate nonperformance by the counterparty over the
term of the commodity derivatives positions. JPMorgan Chase
Bank, NA is a participant in our revolving credit facility and
the collateral for the outstanding borrowings under our
revolving credit facility is used as collateral for our
commodity derivatives.
Unrealized gains and losses, at fair value, are included on our
consolidated balance sheets as current or non-current assets or
liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our
commodity derivative contracts are recorded in earnings as they
occur and included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap
contracts based on the present value of the difference in
exchange-quoted forward price curves and contractual settlement
prices multiplied by notional quantities. We internally valued
the collar contracts using industry-standard option pricing
models and observable market inputs. We use our internal
valuations to determine the fair values of the contracts that
are reflected on our consolidated balance sheets. Realized gains
and losses are also included in other income (expense) on our
consolidated statements of operations.
For the year ended December 31, 2008, we recognized an
unrealized gain of $7.1 million from the change in the fair
value of commodity derivatives. For the year ended
December 31, 2007, we recognized an unrealized loss of
$3.6 million from the change in the fair value of commodity
derivatives. A 10% increase in the NYMEX floating prices would
have resulted in a $1.7 million decrease in the
December 31, 2008 fair value recorded on our balance sheet,
and a corresponding decrease to the gain on commodity
derivatives in our statement of operations.
Effective January 1, 2008, we adopted FAS 157, which
among other things, requires enhanced disclosures about assets
and liabilities carried at fair value. As defined in
FAS 157, fair value is the price that would be received to
sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date
(exit price). We use market data or assumptions that market
participants would use in
46
pricing the asset or liability, including assumptions about risk
and the risks inherent in the inputs to the valuation technique.
These inputs can be readily observable, market corroborated or
generally unobservable. We primarily apply the market approach
for recurring fair value measurements and attempt to use the
best available information. FAS 157 establishes a fair
value hierarchy that prioritizes the inputs used to measure fair
value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or
liabilities (Level 1 measurement) and lowest priority to
unobservable inputs (Level 3 measurement). The three levels
of fair value hierarchy defined by FAS 157 are as follows:
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Level 1 Quoted prices are available in active
markets for identical assets or liabilities as of the reporting
date. At December 31, 2008, we had no Level 1
measurements.
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Level 2 Pricing inputs are other than quoted
prices in active markets included in Level 1, which are
either directly or indirectly observable as of the reporting
date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. These
models are primarily industry-standard models that consider
various assumptions, including quoted forward prices for
commodities, time value, volatility factors and current market
and contractual prices for the underlying instruments, as well
as other relevant economic measures. Our derivatives, which
consist primarily of commodity swaps and collars, are valued
using commodity market data which is derived by combining raw
inputs and quantitative models and processes to generate forward
curves. Where observable inputs are available, directly or
indirectly, for substantially the full term of the asset or
liability, the instrument is categorized in Level 2. At
December 31, 2008, our commodity derivatives were valued
using Level 2 measurements.
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Level 3 Pricing inputs include significant
inputs that are generally less observable from objective
sources. These inputs may be used with internally developed
methodologies that result in managements best estimate of
fair value.
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Item 8.
|
Financial
Statements and Supplementary Data.
|
See Index to Financial Statements on
page F-1
of this report.
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure.
|
None.
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|
Item 9A.
|
Controls
and Procedures.
|
Disclosure
controls and procedures
Our management, with the participation of our President and
Chief Executive Officer and Chief Financial Officer, has
evaluated the effectiveness of our disclosure controls and
procedures (as defined in
Rules 13a-15(e)
and
15d-15(e)
under the Exchange Act) as of December 31, 2008. Based on
this evaluation, our President and Chief Executive Officer and
Chief Financial Officer have concluded that, as of
December 31, 2008, our disclosure controls and procedures
were effective, in that they ensure that information required to
be disclosed by us in the reports that we file or submit under
the Exchange Act is (1) recorded, processed, summarized and
reported within the time periods specified in the SECs
rules and forms, and (2) accumulated and communicated to
our management, including our President and Chief Executive
Officer and Chief Financial Officer, as appropriate to allow
timely decisions regarding required disclosure.
47
Internal
control over financial reporting
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002,
we have included a report of managements assessment of the
design and effectiveness of our internal controls as part of
this annual report on
Form 10-K
for the fiscal year ended December 31, 2008.
Hein & Associates LLP, or Hein, our registered public
accountants, also attested to, and reported on,
managements assessment of the effectiveness of internal
control over financial reporting. Managements report and
Heins attestation report are referenced on
page F-1
under the captions Managements Report on Internal
Control over Financial Reporting and Report of
Independent Registered Public Accounting Firm
Internal Control over Financial Reporting and are
incorporated herein by reference.
No changes to our internal control over financial reporting
occurred during the year ended December 31, 2008 that have
materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting (as
defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act).
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Item 9B.
|
Other
Information.
|
None.
48
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance.
|
Information required under Item 10, Directors,
Executive Officers and Corporate Governance will be
contained under the captions Election of
Directors Directors and Executive
Officers to be provided in our proxy statement for our
2009 annual meeting of stockholders to be filed with the SEC on
or before April 30, 2009, which are incorporated herein by
reference. Additional information regarding our corporate
governance guidelines as well as the complete texts of our Code
of Conduct and the charters of our Audit Committee and our
Nominating and Compensation Committee may be found on our
website at www.approachresources.com.
|
|
Item 11.
|
Executive
Compensation.
|
Information required by Item 11 of this report will be
contained under the caption Executive Compensation
in our proxy statement for our 2009 annual meeting of
stockholders to be filed with the SEC on or before
April 30, 2009, which is incorporated herein by reference.
|
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters.
|
Except as set forth below, the information required by
Item 12 of this report will be contained under the caption
Stock Ownership Matters in our proxy statement for
our 2009 annual meeting of stockholders to be filed with the SEC
on or before April 30, 2009, which is incorporated herein
by reference.
|
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence.
|
Information required by Item 13 of this report will be
contained under the captions Certain Relationships and
Related Party Transactions and Corporate
Governance in our definitive proxy statement for our 2009
annual meeting of stockholders to be filed with the SEC on or
before April 30, 2009, which are incorporated herein by
reference.
|
|
Item 14.
|
Principal
Accountant Fees and Services.
|
Information required by Item 14 of this report will be
contained under the caption Independent Registered Public
Accountants in our definitive proxy statement for our 2009
annual meeting of stockholders to be filed with the SEC on or
before April 30, 2009, which is incorporated herein by
reference.
PART IV
|
|
Item 15.
|
Exhibits
and Financial Statement Schedules.
|
|
|
(a)
|
Documents
filed as part of this report
|
(1) and (2) Financial Statements and Financial
Statement Schedules.
See Index to Consolidated Financial Statements on
page F-1.
(3) Exhibits.
See Index to Exhibits on page 54 for a
description of the exhibits filed as part of this report.
49
GLOSSARY
OF SELECTED OIL AND GAS TERMS
The following is a description of the meanings of some of the
oil and gas industry terms used in this report.
3-D
seismic. (Three Dimensional Seismic Data)
Geophysical data that depicts the subsurface strata in three
dimensions.
3-D seismic
data typically provides a more detailed and accurate
interpretation of the subsurface strata than two dimensional
seismic data.
Basin. A large natural depression on the
earths surface in which sediments generally brought by
water accumulate.
Bbl. One stock tank barrel, of 42
U.S. gallons liquid volume, used herein in reference to
oil, condensate or natural gas liquids.
Bcfe. Billion cubic feet of natural gas
equivalent, determined using the ratio of six Mcf of gas to one
Bbl of oil, condensate or gas liquids.
Btu or British Thermal Unit. The quantity of
heat required to raise the temperature of one pound of water by
one degree Fahrenheit.
Completion. The installation of permanent
equipment for the production of oil or gas.
Developed acreage. The number of acres that
are allocated or assignable to productive wells or wells that
are capable of production.
Developmental well. A well drilled within the
proved boundaries of an oil or gas reservoir with the intention
of completing the stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of
producing hydrocarbons in sufficient quantities such that
proceeds from the sale of such production exceed production
expenses and taxes.
Dry hole costs. Costs incurred in drilling a
well, assuming a well is not successful, including plugging and
abandonment costs.
Exploitation. Ordinarily considered to be a
form of development within a known reservoir.
Exploratory well. A well drilled to find and
produce oil or gas reserves not classified as proved, to find a
new reservoir in a field previously found to be productive of
oil or gas in another reservoir or to extend a known reservoir.
Farmout. An agreement whereby the owner of a
leasehold or working interest agrees to assign an interest in
certain specific acreage to the assignees, retaining an interest
such as an overriding royalty interest, an oil and gas payment,
offset acreage or other type of interest, subject to the
drilling of one or more specific wells or other performance as a
condition of the assignment.
Field. An area consisting of either a single
reservoir or multiple reservoirs, all grouped on or related to
the same individual geological structural feature
and/or
stratigraphic condition.
Fracing or Fracture stimulation
technology. The technique of improving a
wells production or injection rates by pumping a mixture
of fluids into the formation and rupturing the rock, creating an
artificial channel. As part of this technique, sand or other
material may also be injected into the formation to keep the
channel open, so that fluids or gases may more easily flow
through the formation.
Gross acres or gross wells. The total acres or
wells, as the case may be, in which a working interest is owned.
Lease operating expenses. The expenses of
lifting oil or gas from a producing formation to the surface,
and the transportation and marketing thereof, constituting part
of the current operating expenses of a working interest, and
also including labor, superintendence, supplies, repairs, short
lived assets, maintenance, allocated overhead costs, ad valorem
taxes and other expenses incidental to production, but excluding
lease acquisition or drilling or completion expenses.
LNG. Liquefied natural gas.
MBbls. Thousand barrels of oil or other liquid
hydrocarbons.
50
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of oil,
condensate or gas liquids.
MMBoe. Million barrels of oil equivalent, with
six Mcf of natural gas being equivalent to one barrel of oil.
MMBtu. Million British thermal units.
MMcf. Million cubic feet of gas.
MMcfe. Million cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of oil,
condensate or gas liquids.
Net acres or net wells. The sum of the
fractional working interests owned in gross acres or wells, as
the case may be.
NGLs. Natural gas liquids.
NYMEX. New York Mercantile Exchange.
Productive well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production
expenses and taxes.
Prospect. A specific geographic area which,
based on supporting geological, geophysical or other data and
also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery
of commercial hydrocarbons.
Proved developed producing reserves. Proved
developed reserves that are expected to be recovered from
completion intervals currently open in existing wells and
capable of production to market.
Proved developed reserves. Has the meaning
given to such term in
Rule 4-10(a)(3)
of
Regulation S-X,
which defines proved developed reserves as follows:
Proved developed oil and gas reserves are reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected
to be obtained through the application of fluid injection or
other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as
proved developed reserves only after testing by a pilot project
or after the operation of an installed program has confirmed
through production response that increased recovery will be
achieved.
Proved reserves. Has the meaning given to such
term in
Rule 4-10(a)(2)
of
Regulation S-X,
which defines proved reserves as follows:
Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future
conditions.
(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or
conclusive formation test. The area of a reservoir considered
proved includes (A) that portion delineated by drilling and
defined by gas-oil
and/or
oil-water contacts, if any, and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available
geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the proved classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the
following: (A) Oil that may become available from known
reservoirs but is classified separately as indicated additional
reserves; (B) crude oil, natural
51
gas, and natural gas liquids, the recovery of which is subject
to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors; (C) crude
oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales,
coal, gilsonite and other such sources.
Proved undeveloped reserves. Has the meaning
given to such term in
Rule 4-10(a)(4)
of
Regulation S-X,
which defines proved undeveloped reserves as follows:
Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves
be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.
PV-10 or
present value of estimated future net
revenues. An estimate of the present value of the
future net revenues from proved oil and gas reserves after
deducting estimated production and ad valorem taxes, future
capital costs and operating expenses, but before deducting any
estimates of federal income taxes. The estimated future net
revenues are discounted at an annual rate of 10%, in accordance
with the SECs practice, to determine their present
value. The present value is shown to indicate the effect
of time on the value of the revenue stream and should not be
construed as being the fair market value of the properties.
Estimates of
PV-10 are
made using oil and gas prices and operating costs at the date
indicated and held constant for the life of the reserves.
Reserve life index. This index is calculated
by dividing year-end 2008 reserves by estimated 2008 production
of 8,755 MMcfe to estimate the number of years of remaining
production.
Reservoir. A porous and permeable underground
formation containing a natural accumulation of producible oil
and/or gas
that is confined by impermeable rock or water barriers and is
individual and separate from other reservoirs.
Spacing. The distance between wells producing
from the same reservoir. Spacing is expressed in terms of acres,
e.g.,
40-acre
spacing, and is established by regulatory agencies.
Standardized measure. The present value of
estimated future net revenues to be generated from the
production of proved reserves, determined in accordance with the
rules and regulations of the SEC (using prices and costs in
effect as of the period end date) without giving effect to
non-property related expenses such as general and administrative
expenses, debt service and future income tax expenses or to
depletion, depreciation and amortization and discounted using an
annual discount rate of 10%. Standardized measure does not give
effect to derivative transactions.
Successful well. A well that is found to be
capable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceed production
expenses and taxes.
Tight gas sands. A formation with low
permeability that produces natural gas with low flow rates for
long periods of time.
Unconventional resources or reserves. Natural
gas or oil resources or reserves from (i) low-permeability
sandstone and shale formations, such as tight gas and gas
shales, respectively, and (ii) coalbed methane.
Undeveloped acreage. Lease acreage on which
wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil or gas
regardless of whether or not such acreage contains proved
reserves.
Working interest. The operating interest that
gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of
production.
Workover. Operations on a producing well to
restore or increase production.
/d. Per day when used with
volumetric units or dollars.
52
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
APPROACH RESOURCES INC.
J. Ross Craft
President and Chief Executive Officer
Date: March 13, 2009
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities indicated and
on March 13, 2009.
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
/s/ J.
Ross Craft
J.
Ross Craft
|
|
President, Chief Executive Officer and Director
(Principal Executive Officer)
|
|
|
|
/s/ Steven
P. Smart
Steven
P. Smart
|
|
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
|
|
|
|
/s/ Bryan
H. Lawrence
Bryan
H. Lawrence
|
|
Director and Chairman of the Board of Directors
|
|
|
|
/s/ James
H. Brandi
James
H. Brandi
|
|
Director
|
|
|
|
/s/ James
C. Crain
James
C. Crain
|
|
Director
|
|
|
|
/s/ Sheldon
B. Lubar
Sheldon
B. Lubar
|
|
Director
|
|
|
|
/s/ Christopher
J. Whyte
Christopher
J. Whyte
|
|
Director
|
53
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining
adequate internal control over financial reporting (as defined
in
Rule 13a-15(f)
under the Securities Exchange Act of 1934). Our internal control
over financial reporting is designed to provide reasonable
assurance to management and our board of directors regarding the
preparation and fair presentation of published financial
statements. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect
misstatements. Therefore, even those systems determined to be
effective can provide only reasonable assurance with respect to
financial statement preparation and presentation. Management
assessed the effectiveness of our internal control over
financial reporting as of December 31, 2008. In making this
assessment, management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission
(COSO) in Internal Control Integrated Framework.
Based on our assessment, we believe that, as of
December 31, 2008, our internal control over financial
reporting is effective based on those criteria.
|
|
|
|
|
|
|
By:
|
|
/s/ J. Ross Craft
|
|
By:
|
|
/s/ Steven P. Smart
|
|
|
|
|
|
|
|
|
|
J. Ross Craft
President and Chief Executive Officer
|
|
|
|
Steven P. Smart
Executive Vice President and
Chief Financial Officer
|
Fort Worth, Texas
March 13, 2009
F-2
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Approach Resources Inc.
Fort Worth, Texas
We have audited Approach Resources Inc. and subsidiaries
(collectively, the Company) internal control over
financial reporting as of December 31, 2008, based on
criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission. The Companys management is
responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness
of internal control over financial reporting included in the
accompanying Managements Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion
on the Companys internal control over financial reporting
based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our
opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (a) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (b) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (c) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2008, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Approach Resources Inc. and
subsidiaries as of December 31, 2008 and 2007, and the
related consolidated statements of operations, changes in
stockholders equity, cash flows and comprehensive income
for each of the three years in the period ended
December 31, 2008 and our report dated March 9, 2009,
expressed an unqualified opinion.
/s/
HEIN &
ASSOCIATES LLP
Dallas, Texas
March 9, 2009
F-3
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Approach Resources Inc.
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of
Approach Resources Inc. and subsidiaries (collectively, the
Company) as of December 31, 2008 and 2007, and
the related consolidated statements of operations, change in
stockholders equity, cash flows and comprehensive income
for each of the three years in the period ended
December 31, 2008. These financial statements are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Approach Resources Inc. and subsidiaries as of
December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2008, in conformity with
U.S. generally accepted accounting principles.
We have also audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
Companys internal control over financial reporting as of
December 31, 2008, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated March 9, 2009 expressed an
unqualified opinion on the effectiveness of the Companys
internal control over financial reporting.
/s/
HEIN
& ASSOCIATES LLP
Dallas, Texas
March 9, 2009
F-4
Approach
Resources Inc. and Subsidiaries
Consolidated
Balance Sheets
(In
thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
4,077
|
|
|
$
|
4,785
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Joint interest owners
|
|
|
16,228
|
|
|
|
5,272
|
|
Oil and gas sales
|
|
|
5,936
|
|
|
|
5,524
|
|
Unrealized gain on commodity derivatives
|
|
|
8,017
|
|
|
|
793
|
|
Prepaid expenses and other current assets
|
|
|
579
|
|
|
|
432
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
34,837
|
|
|
|
16,806
|
|
PROPERTIES AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil and gas properties, at cost, using the successful efforts
method of accounting
|
|
|
362,805
|
|
|
|
267,246
|
|
Furniture, fixtures and equipment
|
|
|
977
|
|
|
|
433
|
|
|
|
|
|
|
|
|
|
|
|
|
|
363,782
|
|
|
|
267,679
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(60,378
|
)
|
|
|
(36,860
|
)
|
|
|
|
|
|
|
|
|
|
Net properties and equipment
|
|
|
303,404
|
|
|
|
230,819
|
|
OTHER ASSETS
|
|
|
|
|
|
|
1,101
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
338,241
|
|
|
$
|
248,726
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
13,564
|
|
|
$
|
5,459
|
|
Oil and gas sales payable
|
|
|
4,631
|
|
|
|
1,794
|
|
Accrued liabilities
|
|
|
12,580
|
|
|
|
14,764
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
30,775
|
|
|
|
22,017
|
|
NON-CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
43,537
|
|
|
|
|
|
Deferred income taxes
|
|
|
35,891
|
|
|
|
26,342
|
|
Asset retirement obligations
|
|
|
4,225
|
|
|
|
548
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
114,428
|
|
|
|
48,907
|
|
COMMITMENTS AND CONTINGENCIES (Note 11)
|
|
|
|
|
|
|
|
|
STOCKHOLDERS EQUITY:
|
|
|
|
|
|
|
|
|
Preferred stock, $0.01 par value, 10,000,000 shares
authorized none outstanding
|
|
|
|
|
|
|
|
|
Common stock, $0.01 par value, 90,000,000 shares
authorized, 20,715,357 and 20,622,746 issued and 20,680,584 and
20,622,746 outstanding, respectively
|
|
|
207
|
|
|
|
206
|
|
Additional paid-in capital
|
|
|
167,349
|
|
|
|
166,141
|
|
Retained earnings
|
|
|
56,753
|
|
|
|
33,367
|
|
Accumulated other comprehensive income
|
|
|
(496
|
)
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity
|
|
|
223,813
|
|
|
|
199,819
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity
|
|
$
|
338,241
|
|
|
$
|
248,726
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-5
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Operations
(In
thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
79,869
|
|
|
$
|
39,114
|
|
|
$
|
46,672
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
7,621
|
|
|
|
3,815
|
|
|
|
3,889
|
|
Severance and production taxes
|
|
|
4,202
|
|
|
|
1,659
|
|
|
|
1,736
|
|
Exploration
|
|
|
1,478
|
|
|
|
883
|
|
|
|
1,640
|
|
Impairment of non-producing properties
|
|
|
6,379
|
|
|
|
267
|
|
|
|
558
|
|
General and administrative
|
|
|
8,881
|
|
|
|
12,667
|
|
|
|
2,416
|
|
Depletion, depreciation and amortization
|
|
|
23,710
|
|
|
|
13,098
|
|
|
|
14,551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
52,271
|
|
|
|
32,389
|
|
|
|
24,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
27,598
|
|
|
|
6,725
|
|
|
|
21,882
|
|
OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of investment
|
|
|
(917
|
)
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(1,269
|
)
|
|
|
(5,219
|
)
|
|
|
(3,814
|
)
|
Realized gain on commodity derivatives
|
|
|
2,936
|
|
|
|
4,732
|
|
|
|
6,222
|
|
Unrealized gain (loss) on commodity derivatives
|
|
|
7,149
|
|
|
|
(3,637
|
)
|
|
|
8,668
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAX PROVISION
|
|
|
35,497
|
|
|
|
2,601
|
|
|
|
32,958
|
|
INCOME TAX PROVISION (BENEFIT)
|
|
|
12,111
|
|
|
|
(108
|
)
|
|
|
11,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
23,386
|
|
|
$
|
2,709
|
|
|
$
|
21,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
1.13
|
|
|
$
|
0.25
|
|
|
$
|
2.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
1.12
|
|
|
$
|
0.24
|
|
|
$
|
2.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
20,647,339
|
|
|
|
10,976,251
|
|
|
|
9,368,614
|
|
Diluted
|
|
|
20,824,905
|
|
|
|
11,183,707
|
|
|
|
9,634,912
|
|
See accompanying notes to these consolidated financial
statements.
F-6
Approach
Resources Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders
Equity
for the Years Ended December 31, 2006, 2007 and 2008
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loans to
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained
|
|
|
Stockholders,
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
Earnings
|
|
|
Including
|
|
|
Other
|
|
|
|
|
|
|
Common Stock
|
|
|
Paid-in
|
|
|
(Accumulated
|
|
|
Accrued
|
|
|
Comprehensive
|
|
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Deficit)
|
|
|
Interest
|
|
|
Income
|
|
|
Total
|
|
|
BALANCES, January 1, 2006
|
|
|
9,179,721
|
|
|
$
|
92
|
|
|
|
34,440
|
|
|
$
|
9,456
|
|
|
$
|
(4,298
|
)
|
|
$
|
|
|
|
$
|
39,690
|
|
Purchase and cancellation of common stock
|
|
|
(103,845
|
)
|
|
|
(1
|
)
|
|
|
(1,330
|
)
|
|
|
|
|
|
|
334
|
|
|
|
|
|
|
|
(997
|
)
|
Issuance of common stock
|
|
|
428,634
|
|
|
|
4
|
|
|
|
6,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,498
|
|
Issuance of common stock for conversion of stockholder note
|
|
|
230,802
|
|
|
|
2
|
|
|
|
3,498
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,500
|
|
Stock option cancellation payment
|
|
|
|
|
|
|
|
|
|
|
(273
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(273
|
)
|
Share-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Accrual of interest on loans to stockholders, net of related
income tax
|
|
|
|
|
|
|
|
|
|
|
138
|
|
|
|
|
|
|
|
(220
|
)
|
|
|
|
|
|
|
(82
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21,202
|
|
|
|
|
|
|
|
|
|
|
|
21,202
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2006
|
|
|
9,735,312
|
|
|
|
97
|
|
|
|
43,001
|
|
|
|
30,658
|
|
|
|
(4,184
|
)
|
|
|
|
|
|
|
69,572
|
|
Retirement of loans to stockholders
|
|
|
(253,650
|
)
|
|
|
(2
|
)
|
|
|
(4,182
|
)
|
|
|
|
|
|
|
4,184
|
|
|
|
|
|
|
|
|
|
Issuance of common shares to management and directors for
compensation
|
|
|
411,041
|
|
|
|
4
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of stock upon exercise of stock options
|
|
|
72,114
|
|
|
|
1
|
|
|
|
239
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
240
|
|
Share-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
4,646
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,646
|
|
Issuance of common stock upon conversion of convertible notes
|
|
|
1,841,262
|
|
|
|
18
|
|
|
|
20,530
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20,548
|
|
Beneficial conversion feature of convertible notes
|
|
|
|
|
|
|
|
|
|
|
1,547
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,547
|
|
Issuance of shares in initial public offering
|
|
|
6,598,572
|
|
|
|
66
|
|
|
|
73,574
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73,640
|
|
Offering costs related to the initial public offering
|
|
|
|
|
|
|
|
|
|
|
(1,503
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,503
|
)
|
Issuance of shares for acquisition of oil and gas properties
|
|
|
4,239,243
|
|
|
|
42
|
|
|
|
50,829
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,871
|
|
Purchase and cancellation of common stock
|
|
|
(2,021,148
|
)
|
|
|
(20
|
)
|
|
|
(22,536
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,556
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,709
|
|
|
|
|
|
|
|
|
|
|
|
2,709
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
105
|
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2007
|
|
|
20,622,746
|
|
|
|
206
|
|
|
|
166,141
|
|
|
|
33,367
|
|
|
|
|
|
|
|
105
|
|
|
|
199,819
|
|
Issuance of stock upon exercise of stock options
|
|
|
63,459
|
|
|
|
1
|
|
|
|
212
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
213
|
|
Restricted stock issuance
|
|
|
29,152
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based compensation expense
|
|
|
|
|
|
|
|
|
|
|
1,100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,100
|
|
Surrender of restricted shares for payment of income taxes
|
|
|
|
|
|
|
|
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(54
|
)
|
Adjustment to additional
paid-in
capital for tax shortfall upon vesting of restricted shares
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23,386
|
|
|
|
|
|
|
|
|
|
|
|
23,386
|
|
Foreign currency translation adjustments, net of related income
tax of $256
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(601
|
)
|
|
|
(601
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2008
|
|
|
20,715,357
|
|
|
$
|
207
|
|
|
$
|
167,349
|
|
|
$
|
56,753
|
|
|
$
|
|
|
|
$
|
(496
|
)
|
|
|
223,813
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-7
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Cash Flows
(In
thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
23,386
|
|
|
$
|
2,709
|
|
|
$
|
21,202
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
23,710
|
|
|
|
13,098
|
|
|
|
14,551
|
|
Non-cash interest expense on convertible notes
|
|
|
|
|
|
|
2,095
|
|
|
|
|
|
Unrealized (gain) loss on commodity derivatives
|
|
|
(7,149
|
)
|
|
|
3,637
|
|
|
|
(8,668
|
)
|
Impairment of non-producing properties
|
|
|
6,379
|
|
|
|
267
|
|
|
|
558
|
|
Impairment of investment
|
|
|
917
|
|
|
|
|
|
|
|
|
|
Exploration expense
|
|
|
1,478
|
|
|
|
883
|
|
|
|
1,614
|
|
Share-based compensation expense
|
|
|
1,100
|
|
|
|
4,646
|
|
|
|
34
|
|
Deferred income taxes
|
|
|
12,148
|
|
|
|
(296
|
)
|
|
|
11,102
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(11,501
|
)
|
|
|
(2,657
|
)
|
|
|
7,389
|
|
Prepaid expenses and other current assets
|
|
|
(38
|
)
|
|
|
(232
|
)
|
|
|
293
|
|
Accounts payable
|
|
|
8,105
|
|
|
|
(787
|
)
|
|
|
(14,284
|
)
|
Oil and gas sales payable
|
|
|
2,837
|
|
|
|
(3,146
|
)
|
|
|
(1,704
|
)
|
Accrued liabilities
|
|
|
(4,937
|
)
|
|
|
10,529
|
|
|
|
2,218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
56,435
|
|
|
|
30,746
|
|
|
|
34,305
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas properties
|
|
|
(100,089
|
)
|
|
|
(51,845
|
)
|
|
|
(59,352
|
)
|
Additions to furniture, fixtures and equipment, net
|
|
|
(544
|
)
|
|
|
(178
|
)
|
|
|
(32
|
)
|
Investments
|
|
|
|
|
|
|
(917
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(100,633
|
)
|
|
|
(52,940
|
)
|
|
|
(59,384
|
)
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loan origination fees
|
|
|
|
|
|
|
(140
|
)
|
|
|
(69
|
)
|
Borrowings under credit facility
|
|
|
121,687
|
|
|
|
64,285
|
|
|
|
119,547
|
|
Repayment of amounts outstanding under credit facility
|
|
|
(78,150
|
)
|
|
|
(111,904
|
)
|
|
|
(101,353
|
)
|
Proceeds from convertible notes
|
|
|
|
|
|
|
20,000
|
|
|
|
|
|
Borrowing from stockholder
|
|
|
|
|
|
|
|
|
|
|
3,500
|
|
Proceeds from issuance of common stock
|
|
|
213
|
|
|
|
72,377
|
|
|
|
6,498
|
|
Surrender of restricted shares for payment of income taxes
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
Purchase of common stock
|
|
|
|
|
|
|
(22,556
|
)
|
|
|
(997
|
)
|
Stock option cancellation payment
|
|
|
|
|
|
|
|
|
|
|
(273
|
)
|
Income taxes on interest income from loans to stockholders
|
|
|
|
|
|
|
|
|
|
|
(82
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by financing activities
|
|
|
43,696
|
|
|
|
22,062
|
|
|
|
26,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
(502
|
)
|
|
|
(132
|
)
|
|
|
1,692
|
|
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH
EQUIVALENTS
|
|
|
(206
|
)
|
|
|
6
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, beginning of year
|
|
|
4,785
|
|
|
|
4,911
|
|
|
|
3,219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of year
|
|
$
|
4,077
|
|
|
$
|
4,785
|
|
|
$
|
4,911
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
894
|
|
|
$
|
4,117
|
|
|
$
|
3,269
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for income taxes
|
|
$
|
397
|
|
|
$
|
1,287
|
|
|
$
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of stockholder note into common stock
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties
|
|
$
|
509
|
|
|
$
|
60,225
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations capitalized
|
|
$
|
3,504
|
|
|
$
|
257
|
|
|
$
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of convertible notes and accrued interest into common
stock
|
|
$
|
|
|
|
$
|
20,548
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retirement of loans to stockholders in exchange for shares of
common stock
|
|
$
|
|
|
|
$
|
4,184
|
|
|
$
|
334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-8
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial Statements
|
|
1.
|
Summary
of Significant Accounting Policies
|
Organization
and Nature of Operations
Approach Resources Inc. (Approach, ARI,
the Company, we, us or
our) is an independent energy company engaged in the
exploration, development, production and acquisition of
unconventional natural gas and oil properties in the United
States and British Columbia. We focus on finding and developing
natural gas and oil reserves in tight sands and shale gas. We
currently operate or have oil and gas properties or interests in
Texas, Kentucky, British Columbia and New Mexico.
Consolidation,
Basis of Presentation and Significant Estimates
The accompanying consolidated financial statements have been
prepared in accordance with accounting principles generally
accepted in the United States of America and include the
accounts of the Company and its wholly-owned subsidiaries.
Intercompany accounts and transactions are eliminated. In
preparing the accompanying financial statements, management has
made certain estimates and assumptions that affect reported
amounts in the financial statements and disclosures of
contingencies. Actual results may differ from those estimates.
Significant assumptions are required in the valuation of proved
oil and natural gas reserves, the capital expenditure accrual,
share-based compensation, and asset retirement obligations. It
is at least reasonably possible these estimates could be revised
in the near term, and these revisions could be material.
On November 7, 2007, our board of directors approved a
three-for-one stock split in the form of a stock dividend on the
issued and outstanding shares of the Companys common
stock, which became effective at the completion of our initial
public offering (IPO) on November 14, 2007.
Also on November 14, 2007, we acquired all of the
outstanding capital stock of Approach Oil & Gas Inc.
(AOG). The stockholders of AOG received
989,157 shares of Company common stock in exchange for all
of AOGs common shares outstanding at that date.
All common shares and per share amounts in the accompanying
consolidated financial statements and notes to consolidated
financial statements have been adjusted for all periods to give
effect to the stock split and the acquisition of AOG. Certain
prior year amounts have been reclassified to conform to current
year presentation. These classifications have no impact on the
net income reported.
Cash
and Cash Equivalents
We consider all highly liquid debt instruments purchased with an
original maturity of three months or less to be cash
equivalents. At times, the amount of cash and cash equivalents
on deposit in financial institutions exceeds federally insured
limits. We monitor the soundness of the financial institutions
and believe the Companys risk is negligible.
Financial
Instruments
The carrying amounts of financial instruments including cash and
cash equivalents, accounts receivable, notes receivable,
accounts payable and accrued liabilities and long-term debt
approximate fair value, as of December 31, 2008 and 2007.
See Note 8 for commodity derivative fair value disclosures.
F-10
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Oil
and Gas Properties and Operations
Capitalized
Costs
Our oil and gas properties comprised the following at
December 31, (in thousands):
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Mineral interests in properties:
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
12,687
|
|
|
$
|
10,845
|
|
Proved properties
|
|
|
11,849
|
|
|
|
10,937
|
|
Wells and related equipment and facilities
|
|
|
332,289
|
|
|
|
234,067
|
|
Uncompleted wells, equipment and facilities
|
|
|
5,980
|
|
|
|
11,397
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
362,805
|
|
|
|
267,246
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(59,960
|
)
|
|
|
(36,622
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
302,845
|
|
|
$
|
230,624
|
|
|
|
|
|
|
|
|
|
|
We follow the successful efforts method of accounting for our
oil and gas producing activities. Costs to acquire mineral
interests in oil and gas properties and to drill and equip
development wells and related asset retirement costs are
capitalized. Costs to drill exploratory wells are capitalized
pending determination of whether the wells have found proved
reserves. If we determine that the wells do not find proved
reserves, the costs are charged to expense. There were no
exploratory wells capitalized pending determination of whether
the wells found proved reserves at December 31, 2008 or
2007. Geological and geophysical costs, including seismic
studies and costs of carrying and retaining unproved properties
are charged to expense as incurred. We capitalize interest on
expenditures for significant exploration and development
projects that last more than six months while activities are in
progress to bring the assets to their intended use. Through
December 31, 2008, we have capitalized no interest costs
because our exploration and development projects generally last
less than six months. Costs incurred to maintain wells and
related equipment are charged to expense as incurred.
On the sale or retirement of a complete unit of a proved
property, the cost and related accumulated depreciation,
depletion, and amortization are eliminated from the property
accounts, and the resultant gain or loss is recognized. On the
retirement or sale of a partial unit of proved property, the
cost is charged to accumulated depreciation, depletion, and
amortization with a resulting gain or loss recognized in income.
Capitalized amounts attributable to proved oil and gas
properties are depleted by the unit-of-production method over
proved reserves using the unit conversion ratio of 6 Mcf of
gas to 1 Bbl of oil. Depreciation and depletion expense for
oil and gas producing property and related equipment was
$23.3 million, $13.0 million and $14.5 million
for the years ended December 31, 2008, 2007 and 2006,
respectively.
Unproved oil and gas properties that are individually
significant are periodically assessed for impairment of value,
and a loss is recognized at the time of impairment by providing
an impairment allowance. We recorded an impairment of
$6.4 million and $267,000 during the years ended
December 31, 2008 and 2007, respectively related to our
assessment of unproved properties. The impairment recorded
during the year ended December 31, 2008, resulted from
write-offs related to drilling costs in our Boomerang project
and drilling and completion costs in our Northeast British
Columbia project. During the year ended December 31, 2008,
we determined that the future cash flows from drilling costs
relating to these projects will not exceed the capitalized costs
due to market factors. The impairment recorded during the year
ended December 31, 2007, resulted from our conclusion that
proved reserves would not be economically recovered from
approximately 2,282 acres in Ozona Northeast, leases for
which expired in April 2008. We recorded a $558,000
impairment during the year ended December 31, 2006, which
resulted from our leaseholds in our Pecos County, Texas prospect
because we drilled dry holes on the prospect and decided to
abandon drilling efforts in this area.
F-11
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Capitalized costs related to proved oil and gas properties,
including wells and related equipment and facilities, are
evaluated for impairment based on an analysis of undiscounted
future net cash flows in accordance with Statement of Financial
Accounting Standards 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. If undiscounted cash flows
are insufficient to recover the net capitalized costs related to
proved properties, then we recognize an impairment charge in
income from operations equal to the difference between the net
capitalized costs related to unproved properties and their
estimated fair values based on the present value of the related
future net cash flows. We noted no impairment of our proved
properties based on our analysis for the years ended
December 31, 2008, 2007 or 2006.
On the sale of an entire interest in an unproved property for
cash or cash equivalent, gain or loss on the sale is recognized,
taking into consideration the amount of any recorded impairment
if the property had been assessed individually. If a partial
interest in an unproved property is sold, the amount received is
treated as a reduction of the cost of the interest retained.
Oil
and Gas Operations
Revenue
and Accounts Receivable
We recognize revenue for our production when the quantities are
delivered to or collected by the respective purchaser. Prices
for such production are defined in sales contracts and are
readily determinable based on certain publicly available
indices. All transportation costs are included in lease
operating expense.
Accounts receivable, joint interest owners, consist of
uncollateralized joint interest owner obligations due within
30 days of the invoice date. Accounts receivable, oil and
gas sales, consist of uncollateralized accrued revenues due
under normal trade terms, generally requiring payment within 30
to 60 days of production. No interest is charged on
past-due balances. Payments made on all accounts receivable are
applied to the earliest unpaid items. We review accounts
receivable periodically and reduce the carrying amount by a
valuation allowance that reflects our best estimate of the
amount that may not be collectible. No such allowance was
considered necessary at December 31, 2008 or 2007.
Oil and gas sales payable represents amounts collected from
purchasers for oil and gas sales which are either revenues due
to other revenue interest owners or severance taxes due to the
respective state or local tax authorities. Generally, we are
required to remit amounts due under these liabilities within
30 days of the end of the month in which the related
production occurred.
Production
Costs
Production costs, including compressor rental and repair,
pumpers salaries, saltwater disposal, ad valorem taxes,
insurance repairs and maintenance, expensed workovers and other
operating expenses are expensed as incurred and included in
lease operating expense on our consolidated statements of
operations.
Exploration expenses include dry hole costs, delay rentals and
geological and geophysical costs.
Dependence
on Major Customers
For the years ended December 31, 2008, 2007 and 2006, we
sold substantially all of our oil and gas produced to six
purchasers. Additionally, substantially all of our accounts
receivable related to oil and gas sales were due from those six
purchasers at December 31, 2008 and 2007. We believe that
there are potential alternative purchasers and that it may be
necessary to establish relationships with new purchasers.
However, there can be no assurance that we can establish such
relationships and that those relationships will result in
increased purchasers.
F-12
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Dependence
on Suppliers
Our industry is cyclical, and from time to time there is a
shortage of drilling rigs, equipment, supplies and qualified
personnel. During these periods, the costs and delivery times of
rigs, equipment and supplies are substantially greater. If the
unavailability or high cost of drilling rigs, equipment,
supplies or qualified personnel were particularly severe in the
areas where we operate, we could be materially and adversely
affected. We believe that there are potential alternative
providers of drilling services and that it may be necessary to
establish relationships with new contractors. However, there can
be no assurance that we can establish such relationships and
that those relationships will result in increased availability
of drilling rigs.
Other
Property
Furniture, fixtures and equipment are carried at cost.
Depreciation of furniture, fixtures and equipment is provided
using the straight-line method over estimated useful lives
ranging from three to ten years. Gain or loss on retirement or
sale or other disposition of assets is included in income in the
period of disposition. Depreciation expense for other property
and equipment was $180,000, $88,000 and $64,000 for the years
ended December 31, 2008, 2007 and 2006, respectively.
Income
Taxes
Deferred tax assets and liabilities are recognized for the
estimated future tax consequences attributable to the
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases.
Deferred tax assets and liabilities are measured using the tax
rate in effect for the year in which those temporary differences
are expected to be recovered or settled. The effect of a change
in tax rates on deferred tax assets and liabilities is
recognized in income in the year of the enacted tax rate change.
Derivative
Activity
All derivative instruments are recorded on the balance sheet at
fair value. Changes in the instruments fair values are
recognized in the statement of operations immediately unless
specific commodity derivative accounting criteria are met. For
qualifying cash flow commodity derivatives, the gain or loss on
the derivative is deferred in accumulated other comprehensive
income (loss) to the extent the commodity derivative is
effective. The ineffective portion of the commodity derivative
is recognized immediately in the statement of operations. Gains
and losses on commodity derivative instruments included in
cumulative other comprehensive income (loss) are reclassified to
oil and natural gas sales revenue in the period that the related
production is delivered. Derivative contracts that do not
qualify for commodity derivative accounting treatment are
recorded as derivative assets and liabilities at fair value in
the balance sheet, and the associated unrealized gains and
losses are recorded as current income or expense in the
statement of operations.
Historically, we have not designated our derivative instruments
as cash-flow hedges. We record our open derivative instruments
at fair value on our consolidated balance sheets as either
unrealized gains or losses on commodity derivatives. We record
changes in such fair value in earnings on our consolidated
statements of operations under the caption entitled
unrealized gain (loss) on commodity derivatives.
Although we have not designated our derivative instruments as
cash-flow hedges, we use those instruments to reduce our
exposure to fluctuations in commodity prices related to our
natural gas and oil production. Unrealized gains and losses, at
fair value, are included on our consolidated balance sheets as
current or non-current assets or liabilities based on the
anticipated timing of cash settlements under the related
contracts. Changes in the fair value of our commodity derivative
contracts are recorded in earnings as they occur and included in
other income (expense) on our consolidated statements of
operations. Realized gains as losses are also included in other
income (expense) on our consolidated statements of operations.
F-13
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Accrued
Liabilities
Following is a summary of our accrued liabilities at
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Capital expenditures accrued
|
|
$
|
8,173
|
|
|
$
|
13,168
|
|
Operating expenses and other
|
|
|
1,587
|
|
|
|
1,380
|
|
Deferred income tax liabilities
|
|
|
2,770
|
|
|
|
|
|
Income taxes payable
|
|
|
50
|
|
|
|
216
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,580
|
|
|
$
|
14,764
|
|
|
|
|
|
|
|
|
|
|
Asset
Retirement Obligations
Our asset retirement obligations relate to future plugging and
abandonment expenses on oil and gas properties. Based on the
expected timing of payments, the full asset retirement
obligation is classified as non-current. Following is a summary
of our asset retirement obligations for the year ended
December 31, 2008:
|
|
|
|
|
Balance, beginning of period
|
|
$
|
548
|
|
Acquisitions/drilled wells
|
|
|
1,505
|
|
Accretion of discount
|
|
|
191
|
|
Change in assumptions
|
|
|
1,981
|
|
|
|
|
|
|
Balance, end of period
|
|
$
|
4,225
|
|
|
|
|
|
|
The change in assumptions relate primarily to the decrease in
the credit adjusted risk free rate used to value the asset
retirement obligations. The change in the asset retirement
obligations for the twelve months ended December 31, 2007
and 2006 was not significant.
Foreign
Currency Translation
The functional currency of the countries in which we operate is
the U.S. dollar in the United States and the Canadian
Dollar in Canada. Assets and liabilities of our Canadian
subsidiary that are denominated in currencies other than the
Canadian Dollar are translated at current exchange rates. Gains
and losses resulting from such translations, along with gains or
losses realized from transactions denominated in currencies
other than the Canadian Dollar are included in operating results
on our statements of operations. For purposes of consolidation,
we translate the assets and liabilities of our Canadian
Subsidiary into U.S. Dollars at current exchange rates
while revenues and expenses are translated at the average rates
in effect for the period. The related translation gains and
losses are included in accumulated other comprehensive income
within stockholders equity on our consolidated balance
sheets. During the years ended December 31, 2008 and 2007,
we recognized a $601,000 translation loss, net of the related
income tax, and a $105,000 translation gain, respectively.
Transaction gains and losses for the year ended
December 31, 2006 were insignificant.
Share-based
Compensation
We measure and record compensation expense for all share-based
payment awards to employees and outside directors based on
estimated grant-date fair values. We recognize compensation
costs for awards granted over the requisite service period based
on the grant-date fair value.
F-14
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Earnings
Per Common Share
We report basic earnings per common share, which excludes the
effect of potentially dilutive securities, and diluted earnings
per common share, which includes the effect of all potentially
dilutive securities unless their impact is anti-dilutive. The
following are reconciliations of the numerators and denominators
of our basic and diluted earnings per share, (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per-Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
23,386
|
|
|
|
20,647,339
|
|
|
$
|
1.13
|
|
Effect of dilutive securities(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options, treasury method
|
|
|
|
|
|
|
177,566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions
|
|
$
|
23,386
|
|
|
|
20,824,905
|
|
|
$
|
1.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per-Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,709
|
|
|
|
10,976,251
|
|
|
$
|
0.25
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options, treasury method
|
|
|
|
|
|
|
146,908
|
|
|
|
|
|
Non-vested restricted shares(2)
|
|
|
|
|
|
|
60,548
|
|
|
|
|
|
Convertible notes(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions
|
|
$
|
2,709
|
|
|
|
11,183,707
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per-Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
21,202
|
|
|
|
9,368,614
|
|
|
$
|
2.26
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options, treasury method
|
|
|
|
|
|
|
266,298
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions
|
|
$
|
21,202
|
|
|
|
9,634,912
|
|
|
$
|
2.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Approximately 35,000 non-vested restricted shares were excluded
from assumed conversions because they were anti-dilutive for the
year ended December 31, 2008. |
|
(2) |
|
We issued these shares in March 2007. Prior to that time, there
were no restricted shares outstanding. |
|
(3) |
|
The outstanding principal and interest under our convertible
debt was converted on November 7, 2007 into shares of
common stock (see Note 3 for further discussion).
Approximately 1.8 million shares were excluded from assumed
conversions because they were anti-dilutive for the year ended
December 31, 2007. |
The share amounts for the year ending 2006 have been restated to
reflect the contribution agreement and the stock split discussed
in Note 3.
Recently
Issued Accounting Pronouncements
In March 2008, the Financial Accounting Standards Board, or
FASB, issued Statement of Financial Accounting Standard 161,
Disclosures about Derivative Instruments and Hedging Activities,
an amendment of
F-15
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
FASB Statement 133, or SFAS 161. SFAS 161 amends and
expands the disclosure requirements of FASB Statement 133 with
the intent to provide users of financial statement with an
enhanced understanding of (i) how and why an entity uses
derivative instruments, (ii) how derivative instruments and
the related hedged items are accounted for under FASB Statement
133 and its related interpretations, and (iii) how
derivative instruments and related hedged items affect and
entitys financial position, financial performance and cash
flows. SFAS 161 is effective for financial statements
issued for years and interim periods beginning after
November 15, 2008. The effect of adopting SFAS 161 is
not expected to have a significant effect on our reported
financial position or earnings.
In December 2007, FASB issued Statement of Financial Accounting
Standards 141 (revised 2007), Business Combinations, or
SFAS 141(R). SFAS 141(R), among other things,
establishes principles and requirements for how the acquirer in
a business combination (i) recognizes and measures in its
financial statements the identifiable assets acquired, the
liabilities assumed, and any noncontrolling interest in the
acquired business, (ii) recognizes and measures the
goodwill acquired in the business combination or a gain from a
bargain purchase, and (iii) determines what information to
disclose to enable users of the financial statements to evaluate
the nature and financial effects of the business combination.
SFAS 141(R) is effective for fiscal years beginning on or
after December 15, 2008, with early adoption prohibited.
This standard will change our accounting treatment for business
combinations on a prospective basis.
In December 2007, the FASB issued Statement of Financial
Accounting Standards 160, Noncontrolling Interests in
Consolidated Financial Statements, an Amendment of ARB 51,
or SFAS 160. SFAS 160 establishes accounting and
reporting standards for noncontrolling interests in a subsidiary
and for the deconsolidation of a subsidiary. Minority interests
will be recharacterized as noncontrolling interests and
classified as a component of equity. It also establishes a
single method of accounting for changes in a parents
ownership interest in a subsidiary and requires expanded
disclosures. This statement is effective for fiscal years
beginning on or after December 15, 2008, with early
adoption prohibited. The effect of adopting SFAS 160 is not
expected to have a significant effect on our reported financial
position or earnings.
Recent
Developments in Reserve Reporting
On December 31, 2008, the SEC released a Final Rule,
Modernization of Oil and Gas Reporting, updating its oil
and gas reporting requirements. The new reporting requirements
will be effective for our financial statements for the year
ending December 31, 2009 and our 2009 year-end proved
reserve estimates. The new reporting requirements include
provisions that:
|
|
|
|
|
Permit the use of new technologies to establish the reasonable
certainty of proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about
reserves volumes,
|
|
|
|
Allow companies to disclose their probable and possible reserves
in SEC-filed documents (currently, SEC rules limit disclosure to
only proved reserves),
|
|
|
|
Require companies to report the independence and qualifications
of a reserves preparer or auditor,
|
|
|
|
Require companies to file a report when a third party is relied
upon to prepare reserves estimates or conducts a reserves
audit, and
|
|
|
|
Require companies to report oil and gas reserves using an
average price based upon the prior
12-month
period (rather than year-end prices).
|
We are currently evaluating the impact that these new reporting
requirements will have for the year ended December 31, 2009.
F-16
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
2.
|
Ozona
Northeast deep rights acquisition
|
On July 1, 2008, we acquired an additional 95% working
interest in all depths below the top of the Strawn formation,
compression facilities and rights to approximately 75 miles
of gathering lines in our Ozona Northeast field in Crockett and
Schleicher Counties, Texas. The properties were acquired from J.
Cleo Thompson & James Cleo Thompson, Jr., L.P.
and certain other sellers. Before the acquisition, we owned a
100% working interest above the top of the Strawn formation and
a 5% working interest below the top of the Strawn formation in
Ozona Northeast. As a result of the acquisition, we now own
substantially all working interests in all depths of the
subsurface in Ozona Northeast.
The purchase price was $12.0 million subject to
post-closing adjustments. We received a post-closing settlement
of $1.1 million subsequent to December 31, 2008. Of
the purchase price, $500,000 is to be paid no later than one
year from closing pending certain right-of-way matters being
cured. Our preliminary purchase price allocation was
$9.5 million to oil and gas properties and
$2.0 million to gathering system, compression facilities
and related equipment. Funding was provided through borrowings
under our revolving credit facility.
The following is a summary of the purchase price and its
allocation (in thousands):
|
|
|
|
|
Purchase price:
|
|
|
|
|
Cash paid
|
|
$
|
11,500
|
|
Asset retirement obligations assumed
|
|
|
995
|
|
Post-closing purchase price adjustments
|
|
|
(1,154
|
)
|
|
|
|
|
|
Total
|
|
$
|
11,341
|
|
|
|
|
|
|
Allocation:
|
|
|
|
|
Wells, equipment and related facilities
|
|
$
|
11,041
|
|
Mineral interests in oil and gas properties
|
|
|
300
|
|
|
|
|
|
|
Total
|
|
$
|
11,341
|
|
|
|
|
|
|
|
|
3.
|
Contribution
Agreement and Initial Public Offering
|
Contribution
Agreement
On November 14, 2007, the Company acquired all of the
outstanding capital stock of AOG and acquired the 30% working
interest in the Ozona Northeast field (the Neo Canyon
interest) that the Company did not already own from Neo
Canyon Exploration, L.P. (Neo Canyon). Upon the
closing of the contribution agreement, Neo Canyon and each
of the stockholders of AOG received shares of Company common
stock in exchange for their respective contributions. Neo Canyon
received an aggregate of 4,239,243 shares of Company common
stock, of which 2,061,290 shares were offered in the
Companys IPO, 156,805 shares were subject to the
over-allotment option granted to the underwriters and
2,021,148 shares were redeemed by the Company for cash. The
stockholders of AOG received an aggregate of 989,157 shares
of Company common stock.
The acquisition cost of the Neo Canyon interest was
$60.7 million, representing 4,239,243 shares of
Company common stock at $12.00 per share, our IPO price, and the
assumption of related deferred income tax liabilities and asset
retirement obligations at that date along with post-closing
purchase price adjustments resulting from operating results of
the properties acquired between the effective date and the
closing date of the acquisition. The existing tax basis assumed
from the acquisition was finalized during the year ended
December 31, 2008. The adjustment made during the year
ended December 31, 2008 resulted in a $376,000 increase in
deferred tax liabilities, $133,000 in additional post-closing
purchase price adjustments and an
F-17
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
increase in oil and gas properties of $509,000. The following is
a summary of the final purchase price and its allocation (in
thousands):
|
|
|
|
|
Purchase price:
|
|
|
|
|
Issuance of 4,239,243 shares of Approach Resources Inc.
common stock valued at $12.00 per share
|
|
$
|
50,871
|
|
Deferred tax liabilities assumed
|
|
|
9,465
|
|
Asset retirement obligations assumed
|
|
|
133
|
|
Post-closing purchase price adjustments
|
|
|
265
|
|
|
|
|
|
|
Total
|
|
$
|
60,734
|
|
|
|
|
|
|
Allocation:
|
|
|
|
|
Wells, equipment and related facilities
|
|
$
|
59,936
|
|
Mineral interests in oil and gas properties
|
|
|
798
|
|
|
|
|
|
|
Total
|
|
$
|
60,734
|
|
|
|
|
|
|
Our results of operations include the operating results of the
interest acquired from Neo Canyon beginning November 14,
2007. The following condensed pro forma information gives effect
to the acquisition as if it had occurred on January 1,
2006. The pro forma information has been included in the notes
as required by generally accepted accounting principles and is
provided for comparison purposes only. The pro forma financial
information is not necessarily indicative of the financial
results that would have occurred had the acquisition been
effective on the dates indicated and should not be viewed as
indicative of operations in the future.
|
|
|
|
|
|
|
|
|
|
|
Twelve Months
|
|
|
|
Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Operating revenues
|
|
$
|
52,285
|
|
|
$
|
66,230
|
|
Total operating expenses
|
|
$
|
38,651
|
|
|
$
|
33,772
|
|
Earnings applicable to common stock
|
|
$
|
7,224
|
|
|
$
|
27,864
|
|
Net earnings per share basic
|
|
$
|
0.49
|
|
|
$
|
2.05
|
|
Net earnings per share diluted
|
|
$
|
0.49
|
|
|
$
|
2.01
|
|
Initial
Public Offering
On November 14, 2007, we completed the IPO of our common
stock. In connection with our IPO and exercise by the
underwriters of their overallotment option, we sold
6,598,572 shares of our common stock in November 2007 at
$12.00 per share. The gross proceeds of our IPO and
over-allotment option were approximately $79.2 million,
which resulted in net proceeds to the Company of
$73.6 million after deducting underwriter discounts and
commissions of approximately $5.6 million. The aggregate
net proceeds of approximately $73.6 million received by the
Company (in millions) were used as follows:
|
|
|
|
|
Repayment of revolving credit facility
|
|
$
|
51.1
|
|
Repurchase of stock held by selling stockholder
|
|
$
|
22.5
|
|
Stock
Split
A three-for-one stock split in the form of a stock dividend on
the issued and outstanding shares of Company common stock was
declared on November 7, 2007, and was paid on
November 14, 2007 in authorized but unissued shares of
Company common stock to holders of record of shares of common
stock at
F-18
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
the close of business on November 13, 2007, so that each
share of common stock outstanding on that date entitled its
holder to receive two additional shares of common stock.
Convertible
Notes
Upon the consummation of the IPO, the convertible notes
discussed in Note 9, Convertible Notes, and related accrued
interest were automatically converted into shares of our common
stock. The number of shares of common stock issued upon the
automatic conversion of these notes was 920,631 to Yorktown
Energy Partners VII, L.P. and 920,631 to Lubar Equity Fund, LLC.
The shares of common stock that were issued to Yorktown Energy
Partners VII, L.P. and Lubar Equity Fund, LLC upon such
automatic conversion are entitled to the same registration
rights as those provided to certain holders of common stock in
connection with the contribution agreement.
Additionally, we recorded $1.5 million of interest expense
related to a beneficial conversion feature attributable to the
convertible notes at the time of conversion.
|
|
4.
|
Loans to
Stockholders and Stockholder Notes Payable
|
During each of the years ended December 31, 2003 and 2004,
we issued 450,000 shares of common stock in exchange for
$585,000 in cash and $3.9 million in full-recourse notes
receivable from employees and entities owned by or affiliated
with management.
During February 2006, one of our employees voluntarily resigned.
At the time of his resignation, the employee held
103,845 shares of ARI common stock and options to acquire
28,845 shares of ARI common stock at $3.33 per share.
Additionally, the employee owed us $334,000 of principal and
interest under a full-recourse note receivable for the initial
purchase of his shares. On February 17, 2006, we entered
into an agreement to repurchase the shares and options, net of
the principal and interest due under the note receivable. We
paid $12.82 per share, the fair value of our common stock on
February 17, 2006, for the 103,845 shares, or
$1.3 million less the outstanding principal and interest of
$334,000 for total cash of $1.0 million. As discussed in
Note 6, Share-Based Compensation, we paid $273,000 in cash
to cancel the vested options held by the employee on
February 17, 2006.
On January 8, 2007, the remaining notes and accrued
interest were repaid in exchange for 253,650 shares of
common stock held by management, based on the fair value of ARI
common shares of $16.50 per share at that date. The notes
provided for interest at six percent per annum and were payable
upon the earlier of December 31, 2008, the registration of
the underlying common stock, or upon a merger with another
entity or upon a divestiture of our assets. The notes were
collateralized by the underlying common stock purchased and are
reported in the accompanying balance sheet as loans to
stockholders including accrued interest, reducing
stockholders equity. Interest earned is reported net of
related income tax as a component of additional paid-in capital
in the accompanying statement of changes in stockholders
equity.
The following is a summary of the balance of principal and
interest outstanding under the notes receivable at
December 31, 2006, (in thousands):
|
|
|
|
|
|
|
2006
|
|
|
Principal
|
|
$
|
3,614
|
|
Accrued interest
|
|
|
570
|
|
|
|
|
|
|
Total
|
|
$
|
4,184
|
|
|
|
|
|
|
On April 17, 2006, we borrowed $3.5 million from a
stockholder to fund the acquisition of leaseholds in Kentucky.
The terms of the borrowing provided for interest at
6 percent and was due on demand. The borrowing was settled
through the issuance of 230,822 shares of common stock on
July 5, 2006.
F-19
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
We have a $200.0 million revolving loan agreement
(Loan Agreement) with a borrowing base set at
$100.0 million and which is redetermined semi-annually on
or before each April 1 and October 1 based on our oil and gas
reserves. We or the lenders can each request one additional
borrowing base redetermination each calendar year.
The maturity date under the Loan Agreement is July 31,
2010. The borrowings bear interest based on the agent
banks prime rate, or the sum of the LIBOR plus an
applicable margin ranging from 1.25% to 2.00% based on the
borrowings outstanding compared to the borrowing base. We had
outstanding borrowings of $43.5 million at
December 31, 2008. We had no outstanding borrowings at
December 31, 2007. The interest rate applicable to our
outstanding borrowings was 3.3% and 6.6% as of December 31,
2008 and December 31, 2007, respectively. We were in
compliance with the covenants in the Loan Agreement at
December 31, 2008. There are certain restrictions of the
payment of dividends defined in the Loan Agreement that can be
waived by the consent of lenders.
On February 19, 2008, we entered into an amendment
(First Amendment) to our Loan Agreement dated as of
January 18, 2008, among the Company, as borrower, The Frost
National Bank, as administrative agent and lender, JPMorgan
Chase Bank, NA, as lender, and AOG, Approach Oil & Gas
(Canada) Inc. and Approach Resources I, LP, as guarantors.
The First Amendment (i) waives the provisions of
Sections 13(a)(ii) and 13(g) of the Loan Agreement to the
extent that such sections would prohibit the transfer of oil and
gas properties between the Company and any guarantor or between
guarantors under the Loan Agreement, and (ii) amends
Section 13(a)(ii) of the Loan Agreement to permit the
transfer of oil and gas properties between the Company and any
guarantor or between guarantors under the Credit Agreement.
Currently, all guarantors under the Loan Agreement are direct or
indirect wholly-owned subsidiaries of the Company.
On May 6, 2008, we entered into a second amendment (the
Second Amendment) to the Loan Agreement. The Second
Amendment reflected an increase in our borrowing base and
commitments of the lenders to $100 million.
On August 26, 2008, we entered into a third amendment (the
Third Amendment) to the Loan Agreement. The Third
Amendment (i) added Fortis Capital Corp. and KeyBank
National Association as lenders under the Credit Agreement,
(ii) allocated the lenders commitment percentages as
The Frost National Bank 30%, JPMorgan Chase Bank,
NA 30%, Fortis Capital Corp. 20% and
KeyBank National Association 20%, (iii) added a
covenant that we will not exceed a debt to EBITDAX ratio of 3.5
to 1.0, and (iv) clarified that secured parties under the
Loan Agreement (and beneficiaries of Loan Agreement guarantees)
will include affiliates of lenders who enter into commodity
derivatives transactions with us.
We also have outstanding unused letters of credit under the Loan
Agreement totaling $400,000 at December 31, 2008, which
reduce amounts available for borrowing under the Loan Agreement.
|
|
6.
|
Share-Based
Compensation
|
In June 2007, the board of directors and stockholders approved
the 2007 Stock Incentive Plan (the 2007 Plan). Under
the 2007 Plan, we may grant stock options, stock appreciation
rights, restricted stock units, performance awards, unrestricted
stock awards and other incentive awards. The 2007 Plan reserves
10 percent of our outstanding common shares as adjusted on
January 1 of each year, plus shares of common stock that were
available for grant of awards under our prior plan. Awards of
any stock options are to be priced at not less than the fair
market value at the date of the grant. The vesting period of any
stock option award is to be determined by the board at the time
of the grant. The term of each stock option is to be fixed at
the time of grant and may not exceed 10 years. Shares
issued upon stock options exercised are issued as new shares.
F-20
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Share-based compensation expense amounted to $1.1 million,
$4.6 million and $34,000 for the years ended
December 31, 2008, 2007 and 2006, respectively. Such
amounts represent the estimated fair value of options for which
the requisite service period elapsed during the years. There was
no tax benefit recognized in relation to this change.
The fair value of each option granted was estimated using an
option-pricing model with the following weighted average
assumptions during the years ended December 31, 2008 and
2007. There were no grants during the year ended
December 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Expected dividends
|
|
|
|
|
|
|
|
|
Expected volatility
|
|
|
64%
|
|
|
|
68%
|
|
Risk-free interest rate
|
|
|
2.7%
|
|
|
|
3.9%
|
|
Expected life
|
|
|
6 years
|
|
|
|
6 years
|
|
We have not paid out dividends historically, thus the dividend
yields are estimated at zero percent.
Since our shares were not publicly traded prior to the IPO on
November 8, 2007, we used an average of historical
volatility rates based upon other companies within our industry
for awards in 2008 and 2007. Management believes that these
average historical volatility rates are currently the best
available indicator of expected volatility.
The risk-free interest rate is the implied yield available for
zero-coupon U.S. government issues with a remaining term of
five years.
The expected lives of our options are determined based on the
term of the option using the simplified method outlined in Staff
Accounting Bulletin 110.
Assumptions are reviewed each time there is a new grant and may
be impacted by actual fluctuation in our stock price, movements
in market interest rates and option terms. The use of different
assumptions produces a different fair value for the options
granted or modified and impacts the amount of compensation
expense recognized on the consolidated statement of operations.
F-21
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The following table summarizes stock options outstanding and
activity as of and for the years ended December 31, 2008,
2007 and 2006, (dollars in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
Shares
|
|
|
Weighted
|
|
|
Remaining
|
|
|
|
|
|
|
Subject to
|
|
|
Average
|
|
|
Contractual
|
|
|
Aggregate
|
|
|
|
Stock
|
|
|
Exercise
|
|
|
Term
|
|
|
Intrinsic
|
|
|
|
Options
|
|
|
Price
|
|
|
(In Years)
|
|
|
Value
|
|
|
Outstanding at January 1, 2006
|
|
|
375,000
|
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
Canceled
|
|
|
(28,845
|
)
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006
|
|
|
346,155
|
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
205,950
|
|
|
$
|
12.05
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(72,114
|
)
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
479,991
|
|
|
$
|
7.07
|
|
|
|
8.02
|
|
|
$
|
2,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
74,345
|
|
|
$
|
14.90
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(63,459
|
)
|
|
$
|
3.33
|
|
|
|
|
|
|
|
|
|
Canceled
|
|
|
(56,575
|
)
|
|
$
|
12.40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
434,302
|
|
|
$
|
8.47
|
|
|
|
7.34
|
|
|
$
|
837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable (fully vested) at December 31, 2008
|
|
|
262,557
|
|
|
$
|
5.07
|
|
|
|
6.27
|
|
|
$
|
837
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The outstanding share amounts at January 1, 2006 and
December 31, 2006 have been restated to reflect the
contribution agreement and the stock split discussed in
Note 3.
The fair market value of the stock options granted during the
years ended December 31, 2008 and 2007 was $8.96 per share
and $7.69 per share, respectively. Total unrecognized
share-based compensation expense from unvested stock options as
of December 31, 2008 was $1.2 million, and will be
recognized over a remaining service period of 2.25 years.
The intrinsic value of the options exercised during the years
ended December 31, 2008 and 2007 was $770,000 and $634,000,
respectively.
During the year ended December 31, 2006, we paid $273,000
in cash to cancel the vested options held by an employee who
voluntarily resigned. Such amount has been recorded as a
reduction to additional paid in capital as the payment did not
exceed the estimated fair value of the options at the time of
the cancellation.
Share grants totaling 35,948 and 411,041 shares with an
approximate aggregate market value of $733,000 and
$5.2 million at the time of grant were granted during the
years ended December 31, 2008 and 2007, respectively. A
summary of the status of non-vested shares for the years ended
December 31, 2008 and 2007, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant-Date
|
|
|
|
Shares
|
|
|
Fair Value
|
|
|
Nonvested at January 1, 2007
|
|
|
|
|
|
$
|
|
|
Granted
|
|
|
411,041
|
|
|
|
12.70
|
|
Vested
|
|
|
(368,541
|
)
|
|
|
12.26
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2007
|
|
|
42,500
|
|
|
|
16.50
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
35,948
|
|
|
|
20.39
|
|
Vested
|
|
|
(21,250
|
)
|
|
|
16.50
|
|
Canceled
|
|
|
(1,175
|
)
|
|
|
15.48
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2008
|
|
|
56,023
|
|
|
$
|
18.96
|
|
|
|
|
|
|
|
|
|
|
F-22
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The unrecognized compensation of $896,000 related to the
nonvested shares will be recognized over a remaining service
period of 2.83 years.
Our provision (benefit) for income taxes comprised the following
during the years ended December 31, 2008, 2007 and 2006 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(214
|
)
|
|
$
|
188
|
|
|
$
|
550
|
|
State
|
|
|
177
|
|
|
|
|
|
|
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
(37
|
)
|
|
|
188
|
|
|
|
655
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
11,919
|
|
|
|
(296
|
)
|
|
|
11,243
|
|
State
|
|
|
229
|
|
|
|
|
|
|
|
(141
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
12,148
|
|
|
|
(296
|
)
|
|
|
11,102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Provision (benefit) for income taxes
|
|
$
|
12,111
|
|
|
$
|
(108
|
)
|
|
$
|
11,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit) differed from the amounts
computed by applying the U.S. Federal statutory tax rates
to pre-tax income for the years ended December 31, 2008,
2007 and 2006, as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Statutory tax at 34%
|
|
$
|
12,069
|
|
|
$
|
884
|
|
|
$
|
11,205
|
|
State taxes, net of federal impact
|
|
|
199
|
|
|
|
29
|
|
|
|
990
|
|
Changes in enacted rates
|
|
|
|
|
|
|
|
|
|
|
(1,077
|
)
|
Permanent differences(1)
|
|
|
235
|
|
|
|
609
|
|
|
|
|
|
Other differences
|
|
|
(392
|
)
|
|
|
(35
|
)
|
|
|
(173
|
)
|
Change in valuation allowance
|
|
|
|
|
|
|
(1,595
|
)
|
|
|
812
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
12,111
|
|
|
$
|
(108
|
)
|
|
$
|
11,757
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount primarily relates to share-based compensation expense and
the beneficial conversion feature on the convertible notes for
the years ended December 31, 2008 and 2007, respectively. |
In May 2006, the State of Texas enacted a margin tax which will
require us to pay a tax of 1.0% on our taxable
margin, as defined in the law, based on our operating
results beginning January 1, 2007. The margin to which the
tax rate will be applied generally will be calculated as our
gross revenues for federal income tax purposes less the cost of
goods sold, as defined for Texas margin tax purposes. Cost of
goods sold includes the following expenses that are related to
our production of goods: our lease operating expenses,
production taxes, depletion and depreciation expense, labor
costs and intangible drilling costs. Most of our operations are
within the State of Texas. Under the provisions of Statement of
Financial Accounting Standards 109, Accounting for Income Taxes,
we are required to record the effects on deferred taxes for a
change in tax rates or tax law in the period which includes the
enactment date. Previously, our results of operations were
subject to the franchise tax in Texas at a rate of 4.5%, before
consideration of federal benefits of those state taxes.
Temporary differences between book and tax income related to our
oil and gas properties will affect our computation of the Texas
margin tax, and we reduced our deferred tax liabilities by
$1.1 million as of December 31, 2006 as the result of
this change.
F-23
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Deferred tax assets and liabilities are the result of temporary
differences between the financial statement carrying values and
tax bases of assets and liabilities. Our net deferred tax assets
and liabilities are recorded as a long-term liability of
$35.9 million and $26.3 million at December 31,
2008 and 2007, respectively. At December 31, 2008,
$2.8 million of deferred taxes expected to be settled
during 2009 was included in current liabilities within accrued
expenses. Significant components of net deferred tax assets and
liabilities are (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
2,363
|
|
|
$
|
2,846
|
|
Other
|
|
|
694
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
$
|
3,057
|
|
|
$
|
2,846
|
|
Deferred tax liability:
|
|
|
|
|
|
|
|
|
Difference in depreciation, depletion and capitalization
methods oil and gas properties
|
|
|
(38,948
|
)
|
|
|
(28,877
|
)
|
Unrealized gain on commodity derivatives
|
|
|
(2,770
|
)
|
|
|
(301
|
)
|
Other
|
|
|
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(41,718
|
)
|
|
|
(29,188
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax (liability)
|
|
$
|
(38,661
|
)
|
|
$
|
(26,342
|
)
|
|
|
|
|
|
|
|
|
|
At December 31, 2006, AOG provided a valuation allowance
related to its deferred tax assets resulting primarily from net
operating loss carryforwards of $1.6 million, based upon
managements inability to assess the amount to be realized
until completion of the acquisition of AOG capital stock by ARI.
The net operating loss carryforwards at December 31, 2007
of $2.8 million above is related to the release of this
valuation allowance.
Net operating loss carryforwards for tax purposes have the
following expiration dates (in thousands):
|
|
|
|
|
Expiration Dates
|
|
Amounts
|
|
|
2024
|
|
$
|
1,523
|
|
2025
|
|
|
1,082
|
|
2026
|
|
|
2,594
|
|
2027
|
|
|
1,750
|
|
|
|
|
|
|
Total
|
|
$
|
6,949
|
|
|
|
|
|
|
At December 31, 2008, we had the following commodity
derivatives positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
$/MMBtu
|
|
Period
|
|
Monthly
|
|
|
Total
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Fixed
|
|
|
NYMEX Henry Hub
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costless collars 2009
|
|
|
180,000
|
|
|
|
2,160,000
|
|
|
$
|
7.50
|
|
|
$
|
10.50
|
|
|
|
|
|
Costless collars 2009
|
|
|
130,000
|
|
|
|
1,560,000
|
|
|
$
|
8.50
|
|
|
$
|
11.70
|
|
|
|
|
|
WAHA differential
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps 2009
|
|
|
200,000
|
|
|
|
2,400,000
|
|
|
|
|
|
|
|
|
|
|
|
(0.61
|
)
|
Unrealized gains and losses, at fair value, are included on our
consolidated balance sheets as current or non-current assets or
liabilities based on the anticipated timing of cash settlements
under the related contracts. Changes in the fair value of our
commodity derivative contracts are recorded in earnings as they
occur and
F-24
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
included in other income (expense) on our consolidated
statements of operations. We estimate the fair values of swap
contracts based on the present value of the difference in
exchange-quoted forward price curves and contractual settlement
prices multiplied by notional quantities. We internally valued
the collar contracts using industry-standard option pricing
models and observable market inputs. We use our internal
valuations to determine the fair values of the contracts that
are reflected on our consolidated balance sheets. Realized gains
and losses are also included in other income (expense) on our
consolidated statements of operations.
We are exposed to credit losses in the event of nonperformance
by the counterparty on our commodity derivatives positions and
have considered the exposure in our internal valuations.
However, we do not anticipate nonperformance by the counterparty
over the term of the commodity derivatives positions.
Effective January 1, 2008, we adopted FAS 157, which
among other things, requires enhanced disclosures about assets
and liabilities carried at fair value. As defined in
FAS 157, fair value is the price that would be received to
sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date
(exit price). We utilize market data or assumptions that market
participants would use in pricing the asset or liability,
including assumptions about risk and the risks inherent in the
inputs to the valuation technique. These inputs can be readily
observable, market corroborated or generally unobservable. We
primarily apply the market approach for recurring fair value
measurements and attempt to utilize the best available
information. FAS 157 establishes a fair value hierarchy
that prioritizes the inputs used to measure fair value. The
hierarchy gives the highest priority to unadjusted quoted prices
in active markets for identical assets or liabilities
(Level 1 measurement) and lowest priority to unobservable
inputs (Level 3 measurement). The three levels of fair
value hierarchy defined by FAS 157 are as follows:
|
|
|
|
|
Level 1 Quoted prices are available in active
markets for identical assets or liabilities as of the reporting
date. At December 31, 2008, we had no Level 1
measurements.
|
|
|
|
Level 2 Pricing inputs are other than quoted
prices in active markets included in Level 1, which are
either directly or indirectly observable as of the reporting
date. Level 2 includes those financial instruments that are
valued using models or other valuation methodologies. These
models are primarily industry-standard models that consider
various assumptions, including quoted forward prices for
commodities, time value, volatility factors and current market
and contractual prices for the underlying instruments, as well
as other relevant economic measures. Our derivatives, which
consist primarily of commodity swaps and collars, are valued
using commodity market data which is derived by combining raw
inputs and quantitative models and processes to generate forward
curves. Where observable inputs are available, directly or
indirectly, for substantially the full term of the asset or
liability, the instrument is categorized in Level 2. At
December 31, 2008, our commodity derivatives were valued
using Level 2 measurements.
|
|
|
|
Level 3 Pricing inputs include significant
inputs that are generally less observable from objective
sources. These inputs may be used with internally developed
methodologies that result in managements best estimate of
fair value.
|
On June 25, 2007, Yorktown Energy Partners VII, L.P. and
Lubar Equity Fund, LLC loaned an aggregate of $20.0 million
to AOG under two convertible promissory notes of
$10.0 million each. These notes bore interest at a rate of
7.00% per annum and had a maturity date of June 25, 2010,
at which time all principal and interest would have been due.
These notes were initially convertible at the election of the
lender into shares of equity securities of AOG at $100 per share
on December 31, 2007, or earlier if we sold substantially
all of the assets of AOG. Upon consummation of our IPO, the
notes automatically, and without further action required by any
person, converted into shares of ARI common stock. The number of
shares of ARI common stock issued upon the automatic conversion
of these notes was equal to the quotient obtained by dividing
F-25
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
(a) the outstanding principal and accrued interest on each
respective note by (b) the IPO price per share, less any
underwriting discount per share for the shares of ARI common
stock that were issued in our IPO. The shares of our common
stock issued to Yorktown Energy Partners VII, L.P. and Lubar
Equity Fund, LLC upon such automatic conversion are entitled to
the same registration rights as those provided to certain
holders of our common stock in connection with the contribution
agreement. The total principal and interest owed under these
notes at the time of the IPO was $20.5 million. Yorktown
Energy Partners VII, L.P. is an affiliate of Yorktown Partners
LLC, which has one representative, Bryan H. Lawrence, who serves
as a member of our board of directors. Lubar Equity Fund, LLC is
an affiliate of Sheldon B. Lubar, who serves as a member of our
board of directors.
The automatic conversion of the notes into shares of ARI common
stock upon the closing of our IPO constituted a contingent
beneficial conversion feature because the price per share into
which these notes were convertible was less than the price paid
by other parties acquiring ARI common stock. Immediately upon
the closing of our IPO, we were required to measure the
intrinsic value of the beneficial conversion feature and record
such value as a charge to interest expense. The value of the
beneficial conversion feature, and therefore the amount of
interest expense, that was recognized when the notes were
converted on the date of the IPO, was $1.5 million.
|
|
10.
|
Canadian
Unconventional Gas Investment
|
In May 2007, we acquired shares of common stock of a
Canadian-based private exploration company focused on tight gas
and shale gas opportunities in Canada. Our investment amounted
to approximately $917,000 and is a non-controlling interest
accounted for using the cost method at December 31, 2007.
We have written off the carrying value of our minority equity
investment in the Canadian operator by recognizing a non-cash
charge to earnings because we believe we will not recover our
investment.
|
|
11.
|
Commitments
and Contingencies
|
We have employment agreements with our officers and selected
other employees. These agreements are automatically renewed for
successive terms of one year unless employment is terminated at
the end of the term by written notice given to the employee not
less than 60 days prior to the end of such term. Our
maximum commitment under the employment agreements, which would
apply if the employees covered by these agreements were all
terminated without cause, is approximately $1.1 million at
December 31, 2008.
We lease our office space in Fort Worth, Texas under a
non-cancelable agreement that expires on December 31, 2012.
In addition, we have a non-cancelable lease on our former office
space that expires in May 2009. We have sublease agreements for
the former office space providing for a recovery of a
substantial portion of those rentals.
We also have non-cancelable operating lease commitments related
to office equipment that expire by 2012. The following is a
schedule by years of future minimum rental payments required
under our operating lease arrangements, net of minimum rentals
to be received under
non-cancelable
subleases as of December 31, 2008 (in thousands):
|
|
|
|
|
2009
|
|
|
428
|
|
2010
|
|
|
385
|
|
2011
|
|
|
394
|
|
2012
|
|
|
324
|
|
|
|
|
|
|
Total
|
|
|
1,531
|
|
Less: subleases
|
|
|
(49
|
)
|
|
|
|
|
|
Total
|
|
$
|
1,482
|
|
|
|
|
|
|
F-26
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Rent expense under our lease arrangements amounted to $299,000,
$198,000 and $137,000 for the years ended December 31,
2008, 2007 and 2006, respectively.
Litigation
We are involved in various legal and regulatory proceedings
arising in the normal course of business. We do not believe that
an adverse result in any pending legal or regulatory proceeding,
together or in the aggregate, would be material to our
consolidated financial condition, results of operations or cash
flows.
Environmental
Issues
We are engaged in oil and gas exploration and production and may
become subject to certain liabilities as they relate to
environmental clean up of well sites or other environmental
restoration procedures as they relate to the drilling of oil and
gas wells and the operation thereof. In connection with our
acquisition of existing or previously drilled well bores, we may
not be aware of what environmental safeguards were taken at the
time such wells were drilled or during such time the wells were
operated. Should it be determined that a liability exists with
respect to any environmental clean up or restoration, we would
be responsible for curing such a violation. No claim has been
made, nor are we aware of any liability that exists, as it
relates to any environmental clean up, restoration or the
violation of any rules or regulations relating thereto.
|
|
12.
|
Oil and
Gas Producing Activities
|
Set forth below is certain information regarding the costs
incurred for oil and gas property acquisition, development and
exploration activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
2,695
|
|
|
$
|
5,480
|
|
|
$
|
4,071
|
|
Proved properties
|
|
|
12,189
|
|
|
|
59,594
|
|
|
|
356
|
|
Exploration costs
|
|
|
5,007
|
|
|
|
9,897
|
|
|
|
3,769
|
|
Development costs(1)
|
|
|
84,193
|
|
|
|
37,451
|
|
|
|
51,820
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
104,084
|
|
|
$
|
112,422
|
|
|
$
|
60,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
For the year ended December 31, 2008, development costs
include $3.5 million in non-cash asset retirement
obligations recorded in 2008. |
Set forth below is certain information regarding the results of
operations for oil and gas producing activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Revenues
|
|
$
|
79,869
|
|
|
$
|
39,114
|
|
|
$
|
46,672
|
|
Production costs
|
|
|
(11,823
|
)
|
|
|
(5,474
|
)
|
|
|
(5,625
|
)
|
Exploration expense
|
|
|
(1,478
|
)
|
|
|
(883
|
)
|
|
|
(1,640
|
)
|
Impairment
|
|
|
(6,379
|
)
|
|
|
(267
|
)
|
|
|
(558
|
)
|
Depletion
|
|
|
(23,338
|
)
|
|
|
(13,010
|
)
|
|
|
(14,487
|
)
|
Income tax expense
|
|
|
(12,529
|
)
|
|
|
(6,623
|
)
|
|
|
(9,114
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
24,322
|
|
|
$
|
12,857
|
|
|
$
|
15,248
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-27
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
13.
|
Disclosures
About Oil and Gas Producing Activities (unaudited)
|
The estimates of proved reserves and related valuations for the
years ended December 31, 2008, 2007 and 2006 were based
upon the reports prepared by DeGolyer and MacNaughton,
independent petroleum engineers. Each years estimate of
proved reserves and related valuations was prepared in
accordance with the provisions of Statement of Financial
Accounting Standards 69, or SFAS 69, Disclosures about Oil
and Gas Producing Activities. Estimates of proved reserves are
inherently imprecise and are continually subject to revision
based on production history, results of additional exploration
and development, price changes and other factors. All of our oil
and natural gas reserves are attributable to properties within
the United States. A summary of Approachs changes in
quantities of proved oil and natural gas reserves for the years
ended December 31, 2006, 2007 and 2008, are as follows:
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Oil & NGLs
|
|
|
|
(MMcf)
|
|
|
(MBbl)
|
|
|
Balance January 1, 2006
|
|
|
102,405
|
|
|
|
1,086
|
|
Extensions and discoveries
|
|
|
15,655
|
|
|
|
339
|
|
Production
|
|
|
(6,282
|
)
|
|
|
(77
|
)
|
Revisions to previous estimates
|
|
|
(13,121
|
)
|
|
|
(226
|
)
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2006
|
|
|
98,657
|
|
|
|
1,122
|
|
Extensions and discoveries
|
|
|
36,194
|
|
|
|
1,807
|
|
Purchases of minerals in place
|
|
|
40,174
|
|
|
|
378
|
|
Production
|
|
|
(4,801
|
)
|
|
|
(84
|
)
|
Revisions to previous estimates
|
|
|
(9,073
|
)
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2007
|
|
|
161,151
|
|
|
|
3,208
|
|
Extensions and discoveries
|
|
|
22,879
|
|
|
|
3,228
|
|
Purchases of minerals in place
|
|
|
7,312
|
|
|
|
67
|
|
Production
|
|
|
(7,092
|
)
|
|
|
(277
|
)
|
Revisions to previous estimates
|
|
|
(11,383
|
)
|
|
|
141
|
|
|
|
|
|
|
|
|
|
|
Balance December 31, 2008
|
|
|
172,867
|
|
|
|
6,367
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
51,004
|
|
|
|
496
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
70,251
|
|
|
|
1,268
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
84,217
|
|
|
|
3,014
|
|
|
|
|
|
|
|
|
|
|
The following is a discussion of the material changes in our
proved reserve quantities for the years ended December 31,
2008, 2007 and 2006:
Year
Ended December 31, 2008
Our drilling programs in Ozona Northeast, Cinco Terry and North
Bald Prairie resulted in our classification of reserves as
proved, which accounts for the additional quantities listed
under extensions and discoveries. Additionally, during 2008 we
acquired 7,711 MMcfe of proved reserves in Ozona Northeast,
which accounts for the additional proved reserve quantities
listed as purchases of minerals in place. Downward revisions to
proved reserves of 7,405 MMcfe are the result of a
significant decline in commodity prices during the third and
fourth quarters of 2008. The average gas price attributable to
our proved reserves decreased from $8.10 per Mcf at
December 31, 2007 to $6.04 at December 31, 2008.
Downward revisions to proved reserves of 3,132 MMcfe are
also the result of performance in Ozona Northeast and North Bald
Prairie.
F-28
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
Year
Ended December 31, 2007
Our drilling programs in Ozona Northeast, Cinco Terry and North
Bald Prairie resulted in our classification of reserves as
proved, which accounts for the additional quantities listed
under extensions and discoveries. Additionally, we completed the
acquisition of the Neo Canyon interest in Ozona Northeast
accounting for the additional quantities listed as purchases of
minerals in place. The downward revisions to proved reserves are
the result of performance in Ozona Northeast. Partially
offsetting the downward revisions was an increase in the average
gas price attributable to our proved reserves from $6.55 per Mcf
at December 31, 2006 to $8.10 per Mcf at December 31,
2007.
Year
Ended December 31, 2006
Our drilling programs in Ozona Northeast and Cinco Terry
resulted in our classification of reserves as proved, which
accounts for the additional quantities listed under extensions
and discoveries. The average gas price attributable to our
proved reserves decreased from $9.20 per Mcf at
December 31, 2005 to $6.55 per Mcf at December 31,
2006, which was the primary reason for the decrease in
quantities listed under revisions to previous estimates.
The standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves and the changes
in standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves were prepared in
accordance with the provisions of SFAS 69. Future cash
inflows were computed by applying prices at year end to
estimated future production. Future production and development
costs are computed by estimating the expenditures to be incurred
in developing and producing the proved oil and natural gas
reserves at year end, based on year-end costs and assuming
continuation of existing economic conditions.
Future income tax expenses are calculated by applying
appropriate year-end tax rates to future pretax net cash flows
relating to proved oil and natural gas reserves, less the tax
basis of properties involved.
Future income tax expenses give effect to permanent differences,
tax credits and loss carryforwards relating to the proved oil
and natural gas reserves. Future net cash flows are discounted
at a rate of 10% annually to derive the standardized measure of
discounted future net cash flows. This calculation procedure
does not necessarily result in an estimate of the fair market
value of Approachs oil and natural gas properties.
The standardized measure of discounted future net cash flows
relating to proved oil and natural gas reserves are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Future cash flows
|
|
$
|
1,248,661
|
|
|
$
|
1,567,251
|
|
|
$
|
709,184
|
|
Future production costs
|
|
|
(411,177
|
)
|
|
|
(401,579
|
)
|
|
|
(198,023
|
)
|
Future development costs
|
|
|
(201,259
|
)
|
|
|
(191,738
|
)
|
|
|
(108,451
|
)
|
Future income tax expense
|
|
|
(157,503
|
)
|
|
|
(285,384
|
)
|
|
|
(109,784
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
478,722
|
|
|
|
688,550
|
|
|
|
292,926
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(336,087
|
)
|
|
|
(472,590
|
)
|
|
|
(215,049
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
142,635
|
|
|
$
|
215,960
|
|
|
$
|
77,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future cash flows as shown above were reported without
consideration for the effects of commodity derivative
transactions outstanding at each period end. The effect of
commodity derivative transactions on the future cash flows for
the years ended December 31, 2008, 2007 and 2006 was
immaterial.
F-29
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
The changes in the standardized measure of discounted future net
cash flows relating to proved oil and natural gas reserves are
as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Balance, beginning of period
|
|
$
|
215,960
|
|
|
$
|
77,877
|
|
|
$
|
146,439
|
|
Net change in sales and transfer prices and in production
(lifting) costs related to future production
|
|
|
(148,739
|
)
|
|
|
57,231
|
|
|
|
(106,246
|
)
|
Changes in estimated future development costs
|
|
|
(72,754
|
)
|
|
|
(39,506
|
)
|
|
|
(43,229
|
)
|
Sales and transfers of oil and gas produced during the period
|
|
|
(68,037
|
)
|
|
|
(33,640
|
)
|
|
|
(41,047
|
)
|
Net change due to extensions, discoveries and improved recovery
|
|
|
58,249
|
|
|
|
107,864
|
|
|
|
28,418
|
|
Net change due to purchase of minerals in place
|
|
|
10,632
|
|
|
|
97,328
|
|
|
|
|
|
Net change due to revisions in quantity estimates
|
|
|
(14,526
|
)
|
|
|
(21,001
|
)
|
|
|
(22,112
|
)
|
Previously estimated development costs incurred during the period
|
|
|
89,942
|
|
|
|
28,026
|
|
|
|
52,108
|
|
Accretion of discount
|
|
|
29,369
|
|
|
|
12,843
|
|
|
|
15,546
|
|
Other
|
|
|
(8,712
|
)
|
|
|
8,077
|
|
|
|
(4,303
|
)
|
Net change in income taxes
|
|
|
51,251
|
|
|
|
(79,139
|
)
|
|
|
52,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
142,635
|
|
|
$
|
215,960
|
|
|
$
|
77,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average wellhead prices in effect at December 31, 2008,
2007 and 2006 inclusive of adjustments for quality and location
used in determining future net revenues related to the
standardized measure calculation are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Oil (per Bbl)
|
|
$
|
39.60
|
|
|
$
|
93.30
|
|
|
$
|
58.05
|
|
Natural gas liquids (per Bbl)
|
|
$
|
23.00
|
|
|
$
|
60.09
|
|
|
$
|
30.55
|
|
Gas (per Mcf)
|
|
$
|
6.04
|
|
|
$
|
8.10
|
|
|
$
|
6.55
|
|
Selected
Quarterly Financial Data (unaudited), (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 Quarter Ended
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
Net revenue
|
|
$
|
14,692
|
|
|
$
|
22,015
|
|
|
$
|
24,144
|
|
|
$
|
19,018
|
|
Impairment of non-producing properties
|
|
|
(6,379
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net operating expenses
|
|
|
(14,485
|
)
|
|
|
(9,749
|
)
|
|
|
(11,855
|
)
|
|
|
(9,803
|
)
|
Interest expense, net
|
|
|
(355
|
)
|
|
|
(423
|
)
|
|
|
(343
|
)
|
|
|
(148
|
)
|
Impairment of investment
|
|
|
(917
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized gain (loss) on commodity derivates
|
|
|
3,612
|
|
|
|
(195
|
)
|
|
|
(542
|
)
|
|
|
61
|
|
Unrealized gain (loss) on commodity derivatives
|
|
|
3,089
|
|
|
|
18,611
|
|
|
|
(9,672
|
)
|
|
|
(4,879
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(743
|
)
|
|
|
30,259
|
|
|
|
1,732
|
|
|
|
4,249
|
|
Income tax (benefit) provision
|
|
|
(591
|
)
|
|
|
10,411
|
|
|
|
804
|
|
|
|
1,487
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(152
|
)
|
|
$
|
19,848
|
|
|
$
|
928
|
|
|
$
|
2,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.01
|
)
|
|
$
|
0.96
|
|
|
$
|
0.04
|
|
|
$
|
0.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted (loss) net income applicable to common stockholders per
common share
|
|
$
|
(0.01
|
)
|
|
$
|
0.95
|
|
|
$
|
0.04
|
|
|
$
|
0.13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-30
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 Quarter Ended
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
Net revenue
|
|
$
|
11,740
|
|
|
$
|
8,292
|
|
|
$
|
9,690
|
|
|
$
|
9,392
|
|
Net operating expenses
|
|
|
(14,503
|
)
|
|
|
(5,644
|
)
|
|
|
(5,661
|
)
|
|
|
(6,581
|
)
|
Interest expense, net
|
|
|
(2,157
|
)
|
|
|
(1,108
|
)
|
|
|
(998
|
)
|
|
|
(956
|
)
|
Realized gain on commodity derivates
|
|
|
1,409
|
|
|
|
1,080
|
|
|
|
88
|
|
|
|
2,155
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
(1,520
|
)
|
|
|
785
|
|
|
|
1,724
|
|
|
|
(4,626
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes
|
|
|
(5,031
|
)
|
|
|
3,405
|
|
|
|
4,843
|
|
|
|
(616
|
)
|
Income tax (benefit) provision
|
|
|
(3,238
|
)
|
|
|
1,312
|
|
|
|
1,853
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(1,793
|
)
|
|
$
|
2,093
|
|
|
$
|
2,990
|
|
|
$
|
(581
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.12
|
)
|
|
$
|
0.22
|
|
|
$
|
0.32
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net (loss) income applicable to common stockholders per
common share
|
|
$
|
(0.12
|
)
|
|
$
|
0.20
|
|
|
$
|
0.29
|
|
|
$
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 Quarter Ended
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
Net revenue
|
|
$
|
9,885
|
|
|
$
|
10,397
|
|
|
$
|
12,134
|
|
|
$
|
14,256
|
|
Net operating expenses
|
|
|
(6,526
|
)
|
|
|
(6,231
|
)
|
|
|
(6,575
|
)
|
|
|
(5,458
|
)
|
Interest expense, net
|
|
|
(1,047
|
)
|
|
|
(1,058
|
)
|
|
|
(984
|
)
|
|
|
(725
|
)
|
Realized gain on commodity derivatives
|
|
|
2,012
|
|
|
|
1,126
|
|
|
|
1,660
|
|
|
|
1,424
|
|
Unrealized (loss) gain on commodity derivatives
|
|
|
(474
|
)
|
|
|
3,695
|
|
|
|
(745
|
)
|
|
|
6,192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
3,850
|
|
|
|
7,929
|
|
|
|
5,490
|
|
|
|
15,689
|
|
Income tax provision
|
|
|
1,457
|
|
|
|
2,865
|
|
|
|
2,154
|
|
|
|
5,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,393
|
|
|
$
|
5,064
|
|
|
$
|
3,336
|
|
|
$
|
10,409
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic net income applicable to common stockholders per common
share
|
|
$
|
0.25
|
|
|
$
|
0.53
|
|
|
$
|
0.37
|
|
|
$
|
1.14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted net income applicable to common stockholders per common
share
|
|
$
|
0.24
|
|
|
$
|
0.52
|
|
|
$
|
0.36
|
|
|
$
|
1.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-31
Approach
Resources Inc.
Index to
Exhibits
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
3
|
.1
|
|
Restated Certificate of Incorporation of Approach Resources Inc.
(filed as Exhibit 3.1 to the Companys Quarterly Report on
Form 10-Q filed December 13, 2007 and incorporated herein by
reference).
|
|
3
|
.2
|
|
Restated Bylaws of Approach Resources Inc. (filed as Exhibit 3.2
to the Companys Quarterly Report on Form 10-Q filed
December 13, 2007 and incorporated herein by reference).
|
|
4
|
.1
|
|
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the
Companys Registration Statement on Form S-1/A filed
October 18, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.1
|
|
Form of Indemnity Agreement between Approach Resources Inc. and
each of its directors and officers (filed as Exhibit 10.1 to the
Companys Registration Statement on Form S-1/A filed
September 13, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.2
|
|
First Amendment to Form of Indemnity Agreement between Approach
Resources Inc. and each of its directors and officers (filed as
Exhibit 10.5 to the Companys Current Report on Form 8-K
filed December 31, 2008 and incorporated herein by reference).
|
|
10
|
.3
|
|
Employment Agreement by and between Approach Resources Inc. and
J. Ross Craft dated January 1, 2003 (filed as Exhibit 10.3 to
the Companys Registration Statement on Form S-1 filed July
12, 2007 and incorporated herein by reference).
|
|
10
|
.4
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and J. Ross Craft dated December 31, 2008 (filed
as Exhibit 10.2 to the Companys Current Report on Form 8-K
filed December 31, 2008 and incorporated herein by reference).
|
|
10
|
.5
|
|
Employment Agreement by and between Approach Resources Inc. and
Steven P. Smart dated January 1, 2003 (filed as Exhibit
10.4 to the Companys Registration Statement on Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.6
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and Steven P. Smart dated December 31, 2008
(filed as Exhibit 10.3 to the Companys Current Report on
Form 8-K filed December 31, 2008 and incorporated herein by
reference).
|
|
10
|
.7
|
|
Employment Agreement by and between Approach Resources Inc. and
Glenn W. Reed dated January 1, 2003 (filed as Exhibit 10.5
to the Companys Registration Statement on Form S-1 filed
July 12, 2007 and incorporated herein by reference).
|
|
10
|
.8
|
|
First Amendment to Employment Agreement by and between Approach
Resources Inc. and Glenn W. Reed dated December 31,
2008 (filed as Exhibit 10.4 to the Companys Current Report
on Form 8-K filed December 31, 2008 and incorporated herein by
reference).
|
|
10
|
.9
|
|
Approach Resources Inc. 2007 Stock Incentive Plan, effective as
of June 28, 2007 (filed as Exhibit 10.6 to the
Companys Registration Statement on Form S-1 filed July 12,
2007 and incorporated herein by reference).
|
|
10
|
.10
|
|
First Amendment dated December 31, 2008 to Approach Resources
Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007
(filed as Exhibit 10.1 to the Companys Current Report on
Form 8-K filed December 31, 2008 and incorporated herein by
reference).
|
|
10
|
.11
|
|
Form of Business Opportunities Agreement among Approach
Resources Inc. and the other signatories thereto (filed as
Exhibit 10.11 to the Companys Registration Statement on
Form S-1/A filed October 18, 2007 (File No. 333-144512) and
incorporated herein by reference).
|
|
10
|
.12
|
|
Form of Option Agreement under 2003 Stock Option Plan (filed as
Exhibit 10.12 to the Companys Registration Statement on
Form S-1 filed July 12, 2007 and incorporated herein by
reference).
|
|
10
|
.13
|
|
Restricted Stock Award Agreement by and between Approach
Resources Inc. and J. Curtis Henderson dated March 14, 2007
(filed as Exhibit 10.13 to the Companys Registration
Statement on Form S-1 filed July 12, 2007 and incorporated
herein by reference).
|
|
10
|
.14
|
|
Form of Summary of Stock Option Grant under Approach Resources
Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.14 to the
Companys Registration Statement on Form S-1/A filed
October 18, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
54
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
10
|
.15
|
|
Form of Stock Award Agreement under Approach Resources Inc. 2007
Stock Incentive Plan (filed as Exhibit 10.10 to the
Companys Quarterly Report on Form 10-Q filed November 6,
2008 and incorporated herein by reference).
|
|
10
|
.16
|
|
Registration Rights Agreement dated as of November 14, 2007, by
and among Approach Resources Inc. and investors identified
therein (filed as Exhibit 10.1 to the Companys Current
Report on Form 8-K/A filed December 3, 2007 and
incorporated herein by reference).
|
|
10
|
.17
|
|
Gas Purchase Contract dated May 1, 2004 between Ozona Pipeline
Energy Company, as Buyer, and Approach Resources I, L.P.
and certain other parties identified therein (filed as Exhibit
10.18 to the Companys Registration Statement on Form S-1/A
filed September 13, 2007 (File No. 333-144512) and incorporated
herein by reference).
|
|
10
|
.18
|
|
Agreement Regarding Gas Purchase Contract dated May 26, 2006
between Ozona Pipeline Energy Company, as Buyer, and Approach
Resources I, L.P. and certain other parties identified
therein (filed as Exhibit 10.19 to the Companys
Registration Statement on Form S-1/A filed September 13, 2007
(File No. 333-144512) and incorporated herein by reference).
|
|
10
|
.19
|
|
Carry and Earning Agreement dated July 13, 2007 by and between
EnCana Oil & Gas (USA) (filed as Exhibit 10.22 to the
Companys Registration Statement on Form S-1/A filed
September 13, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.20
|
|
Oil & Gas Lease dated February 27, 2007 between the lessors
identified therein and Approach Oil & Gas Inc., as
successor to Lynx Production Company, Inc. (filed as Exhibit
10.23 to the Companys Registration Statement on Form S-1/A
filed September 13, 2007 (File No. 333-144512) and incorporated
herein by reference).
|
|
10
|
.21
|
|
Specimen Oil and Gas Lease for Boomerang prospect between
lessors and Approach Oil & Gas Inc., as successor to The
Keeton Group, LLC, as lessee (filed as Exhibit 10.24 to the
Companys Registration Statement on Form S-1/A filed
September 13, 2007 (File No. 333-144512) and incorporated herein
by reference).
|
|
10
|
.22
|
|
Lease Crude Oil Purchase Agreement dated May 1, 2004 by and
between ConocoPhillips and Approach Operating LLC (filed as
Exhibit 10.26 to the Companys Registration Statement on
Form S-1/A
filed October 18, 2007 (File No. 333-144512) and incorporated
herein by reference).
|
|
10
|
.23
|
|
Gas Purchase Agreement dated as of November 21, 2007 between WTG
Benedum Joint Venture, as Buyer, and Approach Oil & Gas
Inc. and Approach Operating, LLC, as Seller (filed as Exhibit
10.1 to the Companys Current Report on Form 8-K filed
November 28, 2007 and incorporated herein by reference).
|
|
10
|
.24
|
|
$200,000,000 Revolving Credit Agreement dated as of January 18,
2008 among Approach Resources Inc., as borrower, The Frost
National Bank, as administrative agent and lender, and the
financial institutions named therein (filed as Exhibit 10.1 to
the Companys Current Report on Form 8-K filed January 25,
2008 and incorporated herein by reference).
|
|
10
|
.25
|
|
Amendment dated February 19, 2008 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA, as
lender, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1
to the Companys Current Report on Form 8-K filed February
22, 2008 and incorporated herein by reference).
|
|
10
|
.26
|
|
Amendment dated May 6, 2008 to Credit Agreement among Approach
Resources Inc., as borrower, The Frost National Bank, as
administrative agent and lender, JPMorgan Chase Bank, NA, as
lender, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit 99.1
to the Companys Current Report on Form 8-K filed August
28, 2008 and incorporated herein by reference).
|
|
10
|
.27
|
|
Amendment dated August 26, 2008 to Credit Agreement among
Approach Resources Inc., as borrower, The Frost National Bank,
as administrative agent and lender, JPMorgan Chase Bank, NA,
Fortis Capital Corp. and KeyBank National Association, as
lenders, and Approach Oil & Gas Inc., Approach Oil &
Gas (Canada) Inc. and Approach Resources I, LP, as
guarantors, dated as of January 18, 2008 (filed as Exhibit
10.1 to the Companys Current Report on Form 8-K filed
August 28, 2008 and incorporated herein by reference).
|
55
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
14
|
.1
|
|
Code of Conduct (filed as Exhibit 14.1 to the Companys
Annual Report on Form 10-K filed March 28, 2008 and
incorporated herein by reference).
|
|
*21
|
.1
|
|
Subsidiaries.
|
|
*23
|
.1
|
|
Consent of Hein & Associates LLP.
|
|
*23
|
.2
|
|
Consent of DeGolyer and MacNaughton.
|
|
*31
|
.1
|
|
Certification by the President and Chief Executive Officer
Pursuant to Section 302 of the
Sarbanes-Oxley
Act of 2002.
|
|
*31
|
.2
|
|
Certification by the Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002.
|
|
*32
|
.1
|
|
Certification by the President and Chief Executive Officer
Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
*32
|
.2
|
|
Certification by the Chief Financial Officer Pursuant to U.S.C.
Section 1350, as adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
|
|
* |
|
Filed herewith. |
|
|
|
Denotes management contract or compensatory plan or arrangement. |
56