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, 2007
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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
(Registrant’s 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 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 Registrant’s 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. þ
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 þ
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(Do not check if a smaller reporting company)
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Accelerated
filer o
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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 registrant was not a publicly reporting entity as of the
last business day of its most recently completed second quarter
and, therefore, cannot calculate the aggregate market value of
its voting and non-voting common equity held by non-affiliates
as of such date. The aggregate market value of the
registrant’s common voting and non-voting common equity
held by non-affiliates as of December 31, 2007 (based on
the closing price on the Nasdaq Global Market on such date) was
$117.5 million. The number of shares of the
registrant’s common stock, par value $0.01, outstanding as
of March 27, 2008 was 20,622,746.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions of the registrant’s proxy statement for its 2008
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 natural gas
and oil 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
ii
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, management’s
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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our business strategy,
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estimated quantities of gas and oil reserves,
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uncertainty of commodity prices in oil and gas,
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our financial position,
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our cash flow and liquidity,
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replacing our gas and oil 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 gas and oil,
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availability of drilling and production equipment and field
service providers,
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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 gas and oil,
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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
Items 1.
and 2. Business and Properties.
General
We are an independent energy company engaged in the exploration,
development, production and acquisition of unconventional
natural gas and oil properties onshore in the United States and
British Columbia. We focus our growth efforts primarily on
finding and developing natural gas reserves in known tight sands
and shale gas areas and have assembled leasehold interests
aggregating approximately 273,800 gross (191,182 net)
acres. 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 substantially all of our 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 and Canyon Sands)
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Cinco Terry (Wolfcamp, Canyon Sands, 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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Northeast British Columbia
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Montney tight gas and Doig Shale
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North New Mexico
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El Vado East (Mancos Shale)
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Southwest Kentucky
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Boomerang (New Albany Shale)
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At December 31, 2007, we owned working interests in 293
producing oil and gas wells, had estimated proved reserves of
approximately 180.4 Bcfe and were producing
20.2 MMcfe/d (based on production for the month of December
2007). Our average daily net production for the months of
January and February 2008 was 20.3 MMcfe/d and
22.4 MMcfe/d, respectively.
As of December 31, 2007, all of our proved reserves and
production were located in the Ozona Northeast and Cinco Terry
in West Texas and in North Bald Prairie in East Texas. At year
end 2007, our proved reserves were 89% natural gas, 43% proved
developed and had a reserve life index of 21 years (based
on estimated 2008 production of 8.3 Bcfe). In addition to
our producing wells, we have identified 859 total drilling
locations in Ozona Northeast, Cinco Terry and North Bald Prairie
at December 31, 2007, of which 265 are proved.
The standardized measure of discounted future net cash flows of
our proved reserves at December 31, 2007 was
$216.0 million, and our
PV-10 was
$345.7 million.
PV-10 may be
considered a non-GAAP financial measure as defined by the
Securities and Exchange Commission (the “SEC”) 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 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.
Approach was incorporated in 2002. We farmed into the Ozona
Northeast field in 2004 and since that time have added
180.4 Bcfe of proved reserves through our own drilling
efforts in Ozona Northeast, Cinco Terry and North Bald Prairie.
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.
1
Initial
public offering and Neo Canyon acquisition
In November 2007 we completed an initial public offering
(“IPO”) of 8.8 million shares of our common
stock. In connection with the IPO, we acquired the 30% working
interest in Ozona Northeast (the “Neo Canyon
interest”) that we did not already own from Neo Canyon
Exploration, L.P. Neo Canyon received shares of our common stock
for the Neo Canyon interest and was the sole selling stockholder
in our IPO. See Note 2 to our consolidated financial
statements.
Strategy
Our objective is to build 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 developmental properties,
(2) exploring and exploiting our undeveloped properties,
(3) completing strategic acquisitions and
(4) maintaining financial flexibility. 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 859 drilling locations. We
believe we have the technical expertise and operational
experience to maximize the value of these properties. From 2004
through 2007, we drilled over 300 wells in our Ozona
Northeast and Cinco Terry fields in West Texas, making us one of
the 11 most active drillers in West Texas and the second most
active driller in the Canyon Sands during that time period.
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Exploit our undeveloped gas and oil
opportunities. We have over 242,000 gross
acres of undeveloped tight gas and shale gas and oil inventory
to explore and produce. We seek to add proved reserves and
production from these properties through advanced technologies,
including horizontal drilling and advanced fracing and
completion techniques.
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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
(44,600 gross and 44,000 net acres and 140.7 Bcfe
of proved reserves), North Bald Prairie (10,300 gross and
4,850 net acres and 21.4 Bcfe of proved reserves) and
Northeast British Columbia (32,700 gross and 7,425 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 an acquisition of
the property itself could cost.
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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.
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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 are the operator of substantially all of our
producing properties and plan to continue to operate
substantially all 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, 2007, we had no long-term debt outstanding and
$75 million available for borrowings under our revolving
credit facility, providing us with significant financial
flexibility to pursue our business strategy. We currently have
$13.8 million in long-term debt outstanding under our
credit facility.
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2
Oil and
gas properties and operations
West
Texas
Ozona
Northeast (Canyon Sands)
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 44,600 gross (44,000 net) acres.
Beginning with our first well in February 2004, through
December 31, 2007, we have drilled 285 successful wells out
of 303 total wells drilled, for a 94% success rate. As of
December 31, 2007, we had estimated proved reserves of
140.7 Bcfe from Ozona Northeast. We have a 100% working
interest and a net revenue interest of approximately 80% in
Ozona Northeast. Average daily production for January and
February 2008 from Ozona Northeast was 17.6 MMcfe/d (net)
and 17.3 MMcfe/d (net), respectively. We have identified
679 additional drilling locations in Ozona Northeast as of
December 31, 2007, of which 196 are proved. We own and
operate 65 miles of gas gathering lines in the area that
transport our gas to several regional pipeline systems.
Cinco
Terry (Wolfcamp, Canyon Sands and Ellenburger)
Since late 2005, we have leased and acquired options to lease
21,900 gross (9,507 net) acres in our Cinco Terry project,
two miles northwest of the Ozona Northeast border, to evaluate
the Wolfcamp, Canyon and Ellenburger formations. As of
December 31, 2007, we had drilled and completed six Canyon
wells and seven Ellenburger wells and had estimated proved
reserves of 18.3 Bcfe in Cinco Terry. We have approximately
a 50% working interest and 39% net revenue interest in our Cinco
Terry project. Average daily production for January and February
2008 from Cinco Terry was 2.3 MMcfe/d (net) and
3.6 MMcfe/d (net), respectively. We have identified 119
additional drilling locations in our Cinco Terry acreage as of
December 31, 2007, of which 36 are proved. We own and
operate seven miles of gas gathering lines in the area that
transport our gas to several regional pipeline systems.
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 10,300 gross (4,850 net) acres.
We began drilling operations on the initial North Bald Prairie
well in August 2007. As of February 29, 2008, we had
drilled and completed all five wells. We have a 50% working
interest and approximately a 40% net revenue interest in our
North Bald Prairie project. Under our carry and earning
agreement with EnCana, we drilled and we operate the initial
five wells in North Bald Prairie. However, EnCana has the right
to elect to operate the initial five wells. Either party may
propose to drill and operate future wells under the joint
operating agreement between us and EnCana. Average daily
production for January and February 2008 from North Bald Prairie
was 0.5 MMcfe/d (net) and 1.5 MMcfe/d (net),
respectively. 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 61 potential drilling
locations in North Bald Prairie as of December 31, 2007, of
which 33 are proved.
Northeast
British Columbia
Montney
Tight Gas and Doig Shale
In August 2007, we acquired a non-operating, working interest
ranging from 12.3% 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 32,700 gross (7,425 net)
acres. Our primary targets are Triassic-aged tight gas and shale
gas. We participated in one (0.25 net) vertical Montney Sand
3
exploratory well in 2007. In January 2008, we participated in
one (0.25 net) vertical exploratory well. The Canadian operator
plans to frac and complete both the Montney Sand and Doig Shale
zones. A third (0.25 net) well, a horizontal Montney Sand
development well, has been drilled, cased and is waiting on
completion. Royalties are variable month to month depending on
price, volume and product. Royalties for our current prospects
range from a low of less than 10% at low volumes and low prices
to a high of approximately 27% at more substantial prices and
volumes.
North
New Mexico
El Vado
East (Mancos Shale)
Our El Vado East prospect is a 90,300 gross (81,000 net)
acre Mancos Shale play located in the Chama Basin in North
New Mexico in proximity to several productive fields, including
the Puerto Chiquito West and Puerto Chiquito East fields and the
Boulder field, 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 expect
that in the second quarter of 2008 we will spud the first of
eight vertical test wells to be drilled in El Vado East before
April 2009. We have a 90% working interest and a net revenue
interest of approximately 72% in our El Vado East prospect.
Southwest
Kentucky
Boomerang
(New Albany Shale)
Our Boomerang prospect is a 74,000 gross (44,400 net)
acre New Albany Shale play located in Southwest Kentucky in
the Illinois Basin. In the first quarter of 2007, we drilled
three vertical test wells and analyzed cores from these wells.
We currently are formulating a development plan for this
prospect. We have a 60% working interest and a net revenue
interest of approximately 50% in our Boomerang prospect.
4
Natural
gas and oil reserves
The following table sets forth summary information regarding our
estimated proved reserves as of December 31, 2007 and 2006.
See Note 12 “Disclosures about Oil and Gas Producing
Activities (unaudited)” to our consolidated financial
statements for additional information. The company’s
estimated total proved reserves of natural gas and oil as of
December 31, 2007 were 180.4 Bcfe. The 2007 reserves
are composed of 89% natural gas and 11% oil, condensate and
natural gas liquids. The proved developed portion of total
proved reserves at year end 2007 was 43%. The company’s
reserve estimates and
PV-10
(defined below) 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, 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
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—
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2,105
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Proved Undeveloped
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19,319
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—
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19,319
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Total Proved
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21,424
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—
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21,424
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Total
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Proved Developed
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70,251
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1,268
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77,859
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Proved Undeveloped
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90,900
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1,940
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102,541
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Total Proved
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161,151
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3,208
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180,400
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December 31, 2006
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Ozona Northeast
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Proved Developed
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50,652
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403
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53,066
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Proved Undeveloped
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47,339
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524
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50,485
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Total Proved
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97,991
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927
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103,551
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Cinco Terry
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Proved Developed
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352
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94
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914
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Proved Undeveloped
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314
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101
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922
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Total Proved
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666
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195
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1,836
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Total
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Proved Developed
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51,004
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497
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53,980
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Proved Undeveloped
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47,653
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625
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51,407
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Total Proved
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98,657
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1,122
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105,387
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Pro forma for the acquisition of the Neo Canyon interest, our
proved reserves at December 31, 2006 were 148.8 Bcfe.
The standardized measure of discounted future net cash flows for
our proved reserves at December 31, 2007 was
$216.0 million.
5
The present value of our proved reserves, discounted at 10%
(PV-10), was
estimated at $345.7 million, based on year end weighted
average prices of $8.10 per Mcf for natural gas, $93.30 per Bbl
for oil and $60.09 per Bbl for natural gas liquids.
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.
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
estimated proved 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 gas and oil 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands)
|
|
|
PV-10
|
|
$
|
345,656
|
|
|
$
|
128,433
|
|
Less income taxes:
|
|
|
|
|
|
|
|
|
Undiscounted future income taxes
|
|
|
(285,384
|
)
|
|
|
(109,784
|
)
|
10% discount factor
|
|
|
155,688
|
|
|
|
59,228
|
|
|
|
|
|
|
|
|
|
|
Future discounted income taxes
|
|
|
(129,696
|
)
|
|
|
(50,556
|
)
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
215,960
|
|
|
$
|
77,877
|
|
|
|
|
|
|
|
|
|
|
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 presents certain information with respect to
natural gas and oil production attributable to all our interests
in all of our operating areas, the revenue derived from the sale
of such production, average sales prices received and average
production costs during the years ended December 31, 2007,
2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Net Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf)
|
|
|
4,801
|
|
|
|
6,282
|
|
|
|
4,668
|
|
Oil and condensate (MBbls)
|
|
|
84
|
|
|
|
77
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
5,305
|
|
|
|
6,744
|
|
|
|
5,012
|
|
Average Net Daily Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
15
|
|
|
|
18
|
|
|
|
14
|
|
Average Realized Sales Price per Unit (without the effects of
commodity derivatives):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
6.98
|
|
|
$
|
6.66
|
|
|
$
|
8.59
|
|
Oil and condensate (per Bbl)
|
|
|
66.87
|
|
|
|
62.65
|
|
|
|
55.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price (per Mcfe)
|
|
$
|
7.37
|
|
|
$
|
6.92
|
|
|
$
|
8.63
|
|
Average Realized Sales Price per Unit (with the effects of
commodity derivatives):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
7.96
|
|
|
$
|
7.65
|
|
|
$
|
7.96
|
|
Oil and condensate (per Bbl)
|
|
|
66.87
|
|
|
|
62.65
|
|
|
|
55.54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average realized price (per Mcfe)
|
|
$
|
8.26
|
|
|
$
|
7.84
|
|
|
$
|
8.05
|
|
Expenses (per Mcfe)
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
$
|
0.72
|
|
|
$
|
0.58
|
|
|
$
|
0.58
|
|
Severance and production taxes
|
|
|
0.31
|
|
|
|
0.26
|
|
|
|
0.39
|
|
Exploration
|
|
|
0.17
|
|
|
|
0.24
|
|
|
|
0.15
|
|
Impairment of non-producing properties
|
|
|
0.05
|
|
|
|
0.08
|
|
|
|
—
|
|
General and administrative
|
|
|
2.39
|
|
|
|
0.36
|
|
|
|
0.53
|
|
Depletion, depreciation and amortization
|
|
|
2.47
|
|
|
|
2.16
|
|
|
|
1.60
|
|
Productive
wells
The following table sets forth the number of productive gas and
oil wells in which we owned a working interest at
December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
Oil
|
|
|
Total
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Ozona Northeast
|
|
|
278.0
|
|
|
|
264.5
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
279.0
|
|
|
|
265.5
|
|
Cinco Terry
|
|
|
6.0
|
|
|
|
3.0
|
|
|
|
6.0
|
|
|
|
3.0
|
|
|
|
12.0
|
|
|
|
6.0
|
|
North Bald Prairie
|
|
|
2.0
|
|
|
|
1.0
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2.0
|
|
|
|
1.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Productive Wells
|
|
|
286.0
|
|
|
|
268.5
|
|
|
|
7.0
|
|
|
|
4.0
|
|
|
|
293.0
|
|
|
|
272.5
|
|
7
Acreage
The following table summarizes our developed and undeveloped
acreage as of December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Ozona Northeast
|
|
|
27,500
|
|
|
|
26,900
|
|
|
|
17,100
|
|
|
|
17,100
|
|
|
|
44,600
|
|
|
|
44,000
|
|
Cinco Terry
|
|
|
1,900
|
|
|
|
982
|
|
|
|
20,000
|
|
|
|
8,525
|
|
|
|
21,900
|
|
|
|
9,507
|
|
North Bald Prairie
|
|
|
2,100
|
|
|
|
1,050
|
|
|
|
8,200
|
|
|
|
3,800
|
|
|
|
10,300
|
|
|
|
4,850
|
|
El Vado East
|
|
|
—
|
|
|
|
—
|
|
|
|
90,300
|
|
|
|
81,000
|
|
|
|
90,300
|
|
|
|
81,000
|
|
Boomerang
|
|
|
—
|
|
|
|
—
|
|
|
|
74,000
|
|
|
|
44,400
|
|
|
|
74,000
|
|
|
|
44,400
|
|
Northeast British Columbia
|
|
|
—
|
|
|
|
—
|
|
|
|
32,700
|
|
|
|
7,425
|
|
|
|
32,700
|
|
|
|
7,425
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
31,500
|
|
|
|
28,932
|
|
|
|
242,300
|
|
|
|
162,250
|
|
|
|
273,800
|
|
|
|
191,182
|
|
The following table sets forth the number of gross and net
undeveloped acres as of December 31, 2007 that will expire
over the next three years by region unless production is
established within the spacing units covering the acreage prior
to the expiration dates:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Ozona Northeast
|
|
|
14,000
|
|
|
|
13,000
|
|
|
|
3,000
|
|
|
|
2,200
|
|
|
|
—
|
|
|
|
—
|
|
Cinco Terry
|
|
|
11,600
|
|
|
|
3,700
|
|
|
|
1,800
|
|
|
|
1,100
|
|
|
|
6,100
|
|
|
|
3,100
|
|
North Bald Prairie(1)
|
|
|
2,400
|
|
|
|
2,300
|
|
|
|
5,600
|
|
|
|
5,400
|
|
|
|
200
|
|
|
|
200
|
|
El Vado East(2)
|
|
|
—
|
|
|
|
—
|
|
|
|
90,300
|
|
|
|
81,000
|
|
|
|
—
|
|
|
|
—
|
|
Boomerang(3)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
6,400
|
|
|
|
3,800
|
|
Northeast British Columbia
|
|
|
7,700
|
|
|
|
1,200
|
|
|
|
—
|
|
|
|
—
|
|
|
|
22,800
|
|
|
|
5,700
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
35,700
|
|
|
|
20,200
|
|
|
|
100,700
|
|
|
|
89,700
|
|
|
|
35,500
|
|
|
|
12,800
|
|
|
|
|
(1) |
|
Assumes the exercise of options to extend current primary terms
by three additional years (through November 2008) on
approximately 7,700 gross (2,000 net) acres for $125 to
$250 per net acre. |
|
(2) |
|
We have an eight-well drilling commitment during the primary
term, which expires in April 2009. If we meet this requirement,
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. |
|
(3) |
|
Assumes the exercise of options to extend the current primary
terms by three to five additional years (beginning July 2009
through September 2010) on approximately 67,600 gross
(41,000 net) acres for $30 to $45 per net acre. |
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Development:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
51.0
|
|
|
|
46.0
|
|
|
|
81.0
|
|
|
|
53.3
|
|
|
|
115.0
|
|
|
|
74.8
|
|
Non-productive
|
|
|
5.0
|
|
|
|
4.0
|
|
|
|
6.0
|
|
|
|
4.2
|
|
|
|
7.0
|
|
|
|
4.3
|
|
Exploratory:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
—
|
|
|
|
—
|
|
|
|
2.0
|
|
|
|
1.0
|
|
|
|
1.0
|
|
|
|
0.5
|
|
Non-productive
|
|
|
1.0
|
|
|
|
0.7
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2.0
|
|
|
|
1.0
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
51.0
|
|
|
|
46.0
|
|
|
|
83.0
|
|
|
|
54.3
|
|
|
|
116.0
|
|
|
|
75.3
|
|
Non-productive
|
|
|
6.0
|
|
|
|
4.7
|
|
|
|
6.0
|
|
|
|
4.2
|
|
|
|
9.0
|
|
|
|
5.3
|
|
Wells drilled in 2007 are pro forma for the acquisition of 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 demand for, gas and oil. The price we
receive for our gas and oil production depends on numerous
factors beyond our control, including seasonality, the
conditions of the United States economy, particularly in the
manufacturing sector, political conditions in other oil and gas
producing countries, the extent of domestic production and
imports of gas and oil, the proximity and capacity of gas
pipelines and other transportation facilities, demand for oil
and gas, the marketing of competitive fuels and the effects of
state and federal 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, 2007, Ozona Pipeline, an
affiliate of Neo Canyon Exploration, L.P., the selling
stockholder in our IPO, was our most significant purchaser,
accounting for approximately 85.9% of our total 2007 gas and oil
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 gas
and oil production.
All derivative instruments are recorded on the balance sheet at
fair value. Changes in the derivative’s 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 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
9
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 “change in fair value
of 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 gas and oil 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 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 agency’s actions are intended to
foster increased competition within all phases of the gas
industry. To date, the FERC’s 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.
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The 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 and the regulation of the spacing,
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
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. 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 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, imposes 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
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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 RCRA’s 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 results of
operations and financial position.
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.
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.
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Other
laws and regulations
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.
Employees
At March 14, 2008, we had 25 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 materially adverse effect on our
financial position or 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 the Audit Committee and the Compensation and
Nominating Committee, and the 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 public may read and copy
any materials that we file with the SEC at the SEC’s 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.
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
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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
Gas and oil 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 gas and oil. 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 gas and oil fluctuate widely in
response to relatively minor changes in the supply and demand
for gas and oil, market uncertainty and a variety of additional
factors beyond our control, such as:
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domestic and foreign supply of gas and oil,
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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, including the current conflicts in the
Middle East and conditions in South America and Russia,
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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,
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technological advances affecting gas and oil consumption,
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overall United States and global economic conditions, and
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price and availability of alternative fuels.
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Further, gas prices and oil prices do not necessarily fluctuate
in direct relationship to each other. Because more than 89% of
our estimated proved reserves as of December 31, 2007 were
gas reserves, our financial results are more sensitive to
movements in gas prices. In the past, the price of gas has been
extremely volatile, and we expect this volatility to continue.
For example, during the year ended December 31, 2007, the
NYMEX gas spot price ranged from a high of $8.64 per MMBtu to a
low of $5.38 per MMBtu. The NYMEX gas spot price at
December 31, 2007 was $7.47 per MMBtu. At March 19,
2008, the NYMEX gas spot price was $9.02 per MMBtu.
The results of higher investment in the exploration for and
production of gas and other factors may cause the price of gas
to drop. Lower gas and oil prices may not only cause our
revenues to decrease but also may reduce the amount of gas and
oil that we can produce economically. Substantial decreases in
gas and oil 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
financial condition, results of operations and cash flow.
Drilling and exploring for, and producing, gas and oil 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
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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 gas and oil prices,
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limitations in the market for gas and oil,
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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, develop and exploit
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 predrilling
expenditures than traditional drilling strategies.
In addition, higher gas and oil prices generally increase the
demand for drilling rigs, equipment and crews and can lead to
shortages of, and increasing costs for, such drilling equipment,
services and personnel. Such shortages could restrict our
ability to drill the wells and conduct the operations that we
currently have planned. Any delay in the drilling of new wells
or significant increase in drilling costs could adversely affect
our ability to increase our reserves and production and reduce
our revenues.
Currently, all of our producing properties are located in
four counties in Texas, and our proved reserves are primarily
attributable to one field, 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 one field in that area, Ozona Northeast. 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, 2007, 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 2008 and
2015. Options covering approximately 11,600 gross acres in
our Cinco Terry project are scheduled to expire before
June 1, 2008. 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. For the year
ended December 31, 2007, we recorded an
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impairment expense of $267,000 related to the write-off of
2,284 acres in the northwest portion of Ozona Northeast.
This acreage is due to expire in April 2008 and we plan to let
the acreage expire at that time.
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 gas and oil.
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 gas and oil
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 gas and oil reserves, our reserves
and production will decline.
Our future gas and oil 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 gas and oil 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 gas and oil 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 gas and oil reserve information included in this
report represents estimates. Petroleum engineering is a
subjective process of estimating underground accumulations of
gas and oil that cannot be measured in an exact manner.
Estimates of economically recoverable gas and oil 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 gas and oil 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 gas and oil 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 gas and oil prices.
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As of December 31, 2007, approximately 57% 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 cash flows 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 discounted future net cash
flows included in this report should not be considered as the
current market value of the estimated gas and oil reserves
attributable to our properties. As required by the SEC the
estimated discounted future net cash flows from proved reserves
are generally based on prices and costs as of the date of the
measurement (December 31, 2007), while actual future prices
and costs may be materially higher or lower. Actual future net
cash flows 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 gas and oil,
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increases or decreases in consumption, and
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changes in governmental regulations or taxation.
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In addition, the 10% discount factor, which is required by the
SEC to be used to calculate discounted future net cash flows for
reporting purposes, is not necessarily the most appropriate
discount factor based on interest rates in effect from time to
time and risks associated with us or the oil and gas industry in
general.
You should not assume that the present value of future net
revenues from our proved reserves referred to in this report is
the current market value of our estimated gas and oil reserves.
In accordance with SEC requirements, we generally base the
estimated discounted future net cash flows from our proved
reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in
the present value estimate. If gas prices decline by $1.00 per
Mcf from $8.10 per Mcf to $7.10 per Mcf, then our
PV-10 as of
December 31, 2007 would decrease from $345.7 million
to $288.5 million. The average market price received for our
natural gas production for the month of December 31, 2007,
after basis and Btu adjustments, was $7.20 per Mcf.
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. During these periods, the costs and delivery times of
rigs, equipment and supplies are substantially greater. As a
result of historically strong prices of gas, the demand for
oilfield and drilling services has risen, and the costs of these
services may increase. We are particularly sensitive to higher
rig costs and drilling rig availability, as we presently have
three rigs under contract, two of which are on a well-to-well
basis. 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 gas and oil 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
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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 2007, Ozona Pipeline Energy Company, which we refer to as
Ozona Pipeline, and Conoco Phillips accounted for approximately
85.9% and 12.1%, respectively, of our total gas and oil sales
excluding realized commodity derivative settlements. To the
extent that Ozona Pipeline or Conoco Phillips 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. Ozona
Pipeline’s or Conoco Phillips’ 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 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 Senior Vice President —
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 controlling interest in our
company, whose interests may differ from your interests and who
will be able to determine the outcome of matters voted upon by
our stockholders.
At December 31, 2007, 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 45.6% of our
outstanding common stock in the aggregate. In addition, one
Yorktown representative serves on our board of directors, and
our non-Yorktown directors, management team and employees
beneficially own or control approximately 11.4% 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 the vote in any election of directors.
Yorktown, together with our board and management, also has
control over our decisions to enter into significant corporate
transactions and, in their capacity as our majority
stockholders, these stockholders have the ability to prevent any
transactions that they do not believe are in Yorktown’s or
management’s best interest. As a result, Yorktown, together
with our board and management, is able to control, directly or
indirectly and subject to applicable law, 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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•
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changes to other agreements that may adversely affect
us, and
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•
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the payment, or nonpayment, of dividends on our common stock.
|
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.
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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•
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it was presented to the Designated Party solely in that
person’s 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.
|
As a result of this renunciation, our non-employee 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, gas
and oil, 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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•
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price control,
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•
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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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•
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spacing of wells,
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19
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•
|
unitization and pooling of properties,
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•
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safety precautions, and
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•
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permitting requirements.
|
Under these laws and regulations, we could be liable for:
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•
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personal injuries,
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•
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property and natural resource damages,
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•
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well reclamation costs, soil and groundwater remediation
costs, and
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•
|
governmental sanctions, such as fines and penalties.
|
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 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.”
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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•
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well blowouts,
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•
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cratering,
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•
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explosions,
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•
|
uncontrollable flows of gas, oil or well fluids,
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•
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fires,
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•
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pollution, and
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•
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releases of toxic gas.
|
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.
20
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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•
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seasonal variations in gas and oil prices,
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•
|
variations in levels of production, and
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•
|
the completion of exploration and production projects.
|
Market conditions or transportation impediments may hinder
our access to gas and oil markets or delay our
production.
Market conditions, the unavailability of satisfactory gas and
oil processing and transportation may hinder our access to gas
and oil markets or delay our production. Although currently we
control the pipeline operations for a majority of our production
in the Ozona Northeast field, we do not have such control in
other areas where we expect to conduct operations. The
availability of a ready market for our gas and oil production
depends on a number of factors, including the demand for and
supply of gas and oil and the proximity of reserves to pipelines
or trucking and terminal facilities. In addition, the amount of
gas and oil 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, 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 gas and oil 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. 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 gas and oil 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
production or our operations or financial position. 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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•
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diversion of management’s attention,
|
21
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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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•
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an increase in our expenses and working capital requirements.
|
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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•
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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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•
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weather-related damage to our facilities,
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•
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inability to deliver materials to jobsites in accordance with
contract schedules, and
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•
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loss of productivity.
|
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 gas and
oil, potentially putting downward pressure on demand for our
services and causing a reduction in our revenue. Gas and oil
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 gas and oil
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 implement fully 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
capital budget, which is expected to be approximately
$64.3 million for 2008. As of December 31, 2007,
approximately 57% 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
22
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, 2007, no outstanding borrowings existed
under our revolving credit facility. A portion of the proceeds
from our initial public offering repaid a portion of the
outstanding balance under our revolving credit facility. We
currently have $13.8 million in long-term debt outstanding
under our revolving credit facility. The borrowing base
limitation under our revolving credit facility is redetermined
semi-annually. 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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•
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a portion of our cash flow from operations is used to pay
interest on borrowings,
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•
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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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•
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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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•
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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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•
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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.
|
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
gas and oil production, we enter into gas and oil 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
gas and oil 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.
|
Unresolved
Staff Comments.
|
None.
23
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Item 3.
|
Legal
Proceedings.
|
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.
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Item 4.
|
Submission
of Matters to a Vote of Security Holders.
|
None.
PART II
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Item 5.
|
Market
for Registrant’s Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities.
|
Trading
market, range of common stock and number of record
holders
Our common stock is traded on the Nasdaq Global Market
(“Nasdaq”) in the United States under the symbol
“AREX”. Our common stock began trading on Nasdaq on
November 8, 2007. Between that date and December 31,
2007, the high and low closing sales prices of our common stock
as reported on Nasdaq were $13.41 and $12.30, respectively.
As of March 14, 2008, there were 15 record holders of our
common stock.
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.
24
Comparison
of cumulative return
The following graph compares the cumulative return on a $100
investment in our common stock from November 8, 2007 (the
date our common stock trading began on Nasdaq) or
October 31, 2007 in the applicable index, through
December 31, 2007, to that of the cumulative return on a
$100 investment in the Standard & Poor’s 500
Index and the Dow Jones Wilshire Exploration &
Production Index for the same period. In calculating the
cumulative return, reinvestment of dividends, if any, is
assumed. This graph is not “soliciting material,” is
not deemed filed with the SEC and is not to be incorporated by
reference in any of our filings under the Securities Act of 1933
(the “Securities Act”) or the Securities Exchange Act
of 1934 (the “Exchange Act”), whether made before or
after the date hereof and irrespective of any general
incorporation language in any such filing.
Comparison
of Total Return Since November 8, 2007
Among Approach Resources Inc., the Standard &
Poor’s 500 Index and
the Dow Jones Wilshire Exploration & Production
Index
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11/8/2007
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11/30/2007
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12/31/2007
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Approach Resources Inc.
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$
|
100.00
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$
|
102.46
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$
|
102.14
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S&P 500
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100.00
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95.82
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95.15
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D J Wilshire Exploration & Production
|
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100.00
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93.31
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101.09
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25
Recent
sales of unregistered securities
In the three years preceding the filing of this report on
Form 10-K,
we issued and sold the following securities that were not
registered under the Securities Act:
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1.
|
On August 16, 2004, we issued 3,390,000 (split adjusted)
shares of our common stock to Yorktown Energy Partners V,
L.P. and certain of our employees in consideration of
$11,300,000, $1,202,500 of which was evidenced by full recourse
promissory notes secured by pledge of the securities purchased.
These shares were issued in a transaction exempt from the
registration requirements of the Securities Act under Section
4(2) of the Securities Act.
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2.
|
On August 30, 2004, we issued 375,000 (split adjusted)
shares of our common stock to certain of our employees in
consideration of $1,250,000 evidenced by full recourse
promissory notes secured by pledge of the securities purchased.
These shares were issued in a transaction exempt from the
registration requirements of the Securities Act under Section
4(2) of the Securities Act.
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3.
|
On March 14, 2007, we issued 63,750 (split adjusted) shares
of restricted common stock to J. Curtis Henderson, our Executive
Vice President and General Counsel, in connection with
Mr. Henderson’s hiring. These shares were issued in a
transaction exempt from the registration requirements of the
Securities Act pursuant to Rule 701 under the Securities
Act.
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4.
|
On June 25, 2007, Approach Oil & Gas Inc.
(“AOG”) issued convertible promissory notes to each of
Yorktown Energy Partners VII, L.P. and Lubar Equity Fund, LLC in
the aggregate amount of $20,000,000. The notes and accrued
interest of approximately $548,000 automatically converted into
1,841,262 (split adjusted) shares of our common stock upon the
completion of our IPO on November 14, 2007. The number of
shares of common stock issued upon the automatic conversion of
these notes was equal to the quotient obtained by dividing
(a) the outstanding principal and accrued interest on each
respective note by (b) the IPO price per share less
underwriting discounts. These shares issued upon the conversion
of these notes were issued in a transaction exempt from the
registration requirements of the Securities Act under
Section 4(2) of the Securities Act.
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5.
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On July 20, 2007, we issued 72,114 (split adjusted) shares
of common stock pursuant to the exercise of stock options held
by a former executive officer at an exercise price of $3.33 per
share. The issuance of these shares was exempt from the
registration requirements of the Securities Act pursuant to
Rule 701.
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6.
|
On November 14, 2007, we completed the IPO of our common
stock pursuant to our registration statement on
Form S-1
(File
333-144512)
declared effective by the SEC on November 8, 2007. The
underwriters for the offering were J.P. Morgan Securities
Inc., Wachovia Capital Markets, LLC, KeyBanc Capital Markets
Inc. and Tudor, Pickering, Holt & Co. Securities, Inc.
Pursuant to the registration statement, we registered the offer
and sale of 8,816,667 shares of our $0.01 par value
common stock, which included 2,061,290 shares sold by the
selling stockholder and 1,150,000 shares subject to an
option granted to the underwriters by us to cover
over-allotments. The underwriters exercised their over-allotment
option on November 14, 2007. The sale of the shares in our
IPO closed on November 14, 2007 and the sale of the shares
covered by the over-allotment option closed on November 16,
2007. Our IPO terminated upon completion of the closing.
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The gross proceeds of our IPO, including the gross proceeds from
over-allotment option, based on the IPO price of $12.00 per
share, were approximately $79.2 million, which resulted in
(a) net proceeds to the Company of $73.6 million after
deducting underwriter discounts and commissions
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26
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of approximately $5.6 million, and (b) net proceeds to
the selling stockholder of approximately $23.0 million. We
did not receive any proceeds from the sale of the shares by the
selling stockholder. We also paid for legal fees incurred by the
selling stockholder. Other than for such fees, no fees or
expenses have been paid, directly or indirectly, to any officer,
director or 10% stockholder or other affiliate. The net proceeds
from our IPO were used to (a) repay a portion of our
revolving credit facility in November 2007 totaling
$51.1 million and (b) repurchase 2,021,148 shares
of our common stock held by the selling stockholder for
approximately $22.5 million.
|
Issuer
repurchases of equity securities
Except as discussed above under “Recent sales of
unregistered securities” with respect to the repurchase of
2,021,148 shares of our common stock from the selling
stockholder in November 2007 for approximately
$22.5 million, we made no repurchases of our common stock
during the year ended December 31, 2007.
27
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Item 6.
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Selected
Financial Data.
|
The following table sets forth selected financial information
for the five years ended December 31, 2007. 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 AOG under a contribution agreement effective
November 14, 2007. This information should be read in
conjunction with Item 7 of this report,
“Management’s 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.
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Year Ended December 31,
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2007
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2006
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2005
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2004
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2003
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(In thousands, except per share data)
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Operating results data
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Revenues:
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Oil and gas sales
|
|
$
|
39,114
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$
|
46,672
|
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$
|
43,264
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$
|
5,682
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|
$
|
—
|
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Expenses:
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Lease operating expense
|
|
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3,815
|
|
|
|
3,889
|
|
|
|
2,910
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|
|
|
179
|
|
|
|
—
|
|
Severance and production taxes
|
|
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1,659
|
|
|
|
1,736
|
|
|
|
1,975
|
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|
|
407
|
|
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|
—
|
|
Exploration
|
|
|
883
|
|
|
|
1,640
|
|
|
|
733
|
|
|
|
2,396
|
|
|
|
442
|
|
Impairment of non-producing activities
|
|
|
267
|
|
|
|
558
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
General and administrative
|
|
|
12,667
|
|
|
|
2,416
|
|
|
|
2,659
|
|
|
|
1,943
|
|
|
|
1,535
|
|
Depletion, depreciation and amortization
|
|
|
13,098
|
|
|
|
14,551
|
|
|
|
8,011
|
|
|
|
1,224
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
32,389
|
|
|
|
24,790
|
|
|
|
16,288
|
|
|
|
6,149
|
|
|
|
1,986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
|
6,725
|
|
|
|
21,882
|
|
|
|
26,976
|
|
|
|
(467
|
)
|
|
|
(1,986
|
)
|
Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest (expense) income, net
|
|
|
(5,219
|
)
|
|
|
(3,814
|
)
|
|
|
(802
|
)
|
|
|
201
|
|
|
|
59
|
|
Realized gain (loss) on commodity derivatives
|
|
|
4,732
|
|
|
|
6,222
|
|
|
|
(2,925
|
)
|
|
|
—
|
|
|
|
—
|
|
Change in fair value of commodity derivatives
|
|
|
(3,637
|
)
|
|
|
8,668
|
|
|
|
(4,163
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before (benefit) provision for income taxes
|
|
|
2,601
|
|
|
|
32,958
|
|
|
|
19,086
|
|
|
|
(266
|
)
|
|
|
(1,927
|
)
|
(Benefit) provision for income taxes
|
|
|
(108
|
)
|
|
|
11,756
|
|
|
|
7,028
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
2,709
|
|
|
$
|
21,202
|
|
|
$
|
12,058
|
|
|
$
|
(266
|
)
|
|
$
|
(1,927
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.25
|
|
|
$
|
2.26
|
|
|
$
|
1.32
|
|
|
$
|
(0.05
|
)
|
|
$
|
(1.15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.24
|
|
|
$
|
2.20
|
|
|
$
|
1.32
|
|
|
$
|
(0.05
|
)
|
|
$
|
(1.15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of cash flows data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
30,746
|
|
|
$
|
34,305
|
|
|
$
|
40,588
|
|
|
$
|
4,528
|
|
|
$
|
(2,391
|
)
|
Investing activities
|
|
|
(52,940
|
)
|
|
|
(59,384
|
)
|
|
|
(72,224
|
)
|
|
|
(26,859
|
)
|
|
|
(15
|
)
|
Financing activities
|
|
|
22,062
|
|
|
|
26,771
|
|
|
|
32,199
|
|
|
|
22,474
|
|
|
|
4,898
|
|
Balance sheet data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
4,785
|
|
|
$
|
4,911
|
|
|
$
|
3,219
|
|
|
$
|
2,656
|
|
|
$
|
2,513
|
|
Other current assets
|
|
|
12,362
|
|
|
|
13,200
|
|
|
|
16,305
|
|
|
|
6,458
|
|
|
|
410
|
|
Property, equipment, net, successful efforts method
|
|
|
230,478
|
|
|
|
132,112
|
|
|
|
88,803
|
|
|
|
24,223
|
|
|
|
35
|
|
Other assets
|
|
|
1,101
|
|
|
|
86
|
|
|
|
89
|
|
|
|
1,565
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
$
|
108,416
|
|
|
$
|
34,902
|
|
|
$
|
2,958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
22,017
|
|
|
$
|
15,421
|
|
|
$
|
32,746
|
|
|
$
|
9,827
|
|
|
$
|
86
|
|
Long-term debt
|
|
|
—
|
|
|
|
47,619
|
|
|
|
29,425
|
|
|
|
100
|
|
|
|
—
|
|
Other long-term debt liabilities
|
|
|
26,890
|
|
|
|
17,697
|
|
|
|
6,555
|
|
|
|
99
|
|
|
|
—
|
|
Stockholders’ equity
|
|
|
199,819
|
|
|
|
69,572
|
|
|
|
39,690
|
|
|
|
24,876
|
|
|
|
2,872
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders’ equity
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
$
|
108,416
|
|
|
$
|
34,902
|
|
|
$
|
2,958
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
Item 7.
|
Management’s
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 onshore in the United States and
British Columbia. We are focusing our growth efforts primarily
on finding and developing natural gas reserves in known tight
gas sands and shale areas and have assembled leasehold interests
aggregating approximately 273,800 gross (191,182 net)
acres. We expect to leverage our management team’s proven
track record of finding and exploiting unconventional reservoirs
through advanced completion, fracturing and drilling techniques.
As the operator of substantially all of our 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 and Canyon Sands)
|
|
|
•
|
Cinco Terry (Wolfcamp, Canyon Sands, Ellenburger)
|
East Texas
|
|
|
|
•
|
North Bald Prairie (Cotton Valley Sands, Bossier and Cotton
Valley Lime)
|
Northeast British Columbia
|
|
|
|
•
|
Montney tight gas and Doig Shale
|
North New Mexico
|
|
|
|
•
|
El Vado East (Mancos Shale)
|
Southwest Kentucky
|
|
|
|
•
|
Boomerang (New Albany 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, 2007, we owned working interests in 293
producing oil and gas wells, had estimated proved reserves of
approximately 180.4 Bcfe and were producing
20.2 MMcfe/d (based on production for the month of December
2007). Our average daily net production for the months of
January and February 2008 was 20.3 MMcfe/d and
22.4 MMcfe/d, respectively.
As of December 31, 2007, 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
2007, our proved reserves were 89% natural gas, 43% proved
developed and had a reserve life index of 21 years (based
on estimated 2008 production of 8.3 Bcfe). In addition to
our producing wells, we had identified 859 total drilling
locations in Ozona Northeast, Cinco Terry and North Bald Prairie
at December 31, 2007.
29
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 capacity constraints, inventory
storage levels, gas price differentials and other factors. 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. 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.
Higher oil and gas prices have led to higher demand for drilling
rigs, operating personnel and field supplies and services and
have caused increases in the costs of those goods and services.
To date, the higher sales prices have more than offset the
higher drilling and operating costs. Given the inherent
volatility of gas prices, which are influenced by many factors
beyond our control, we plan our activities and budget based on
conservative sales price assumptions, which generally are lower
than the average sales prices received. 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. At
the completion of our IPO, we repaid all amounts outstanding
under our revolving credit facility plus accrued interest. 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.
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 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
Accounting for oil and gas activities is subject to special,
unique rules. We use the successful efforts method for
accounting for our oil and gas activities. The significant
principles for this method are:
|
|
|
|
•
|
geological and geophysical evaluation costs are expensed as
incurred,
|
|
|
•
|
dry holes for exploratory wells are expensed, and dry holes for
developmental wells are capitalized, and
|
|
|
•
|
impairments of properties, if any, are based on the evaluation
of the carrying value of properties against their fair value
based upon pools of properties grouped by geographical and
geological conformity.
|
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
30
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, 2007 proved reserves volumes would have
resulted in approximately $1.4 million of additional
depletion expense for the year ended December 31, 2007.
Our estimated proved reserves as of December 31, 2007 were
prepared by DeGolyer and MacNaughton.
Derivative
instruments and commodity derivative activities
All derivative instruments are recorded on the balance sheet at
fair value. We determine the fair value of our derivatives by
estimating the present value of future net cash flows expected
from those contracts. We compute the estimate by multiplying the
notional quantities specified in our contracts by the difference
between exchange-quoted forward prices and the strike price
specified in our contracts. We then compute the present value of
those cash flows using our credit-adjusted risk-free rate under
our credit agreement. Changes in the derivative’s 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 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 “change
in fair value of 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, 2007, we recognized an unrealized loss of
$3.6 million from the change in the fair value of commodity
derivatives. For the year ended December 31, 2006, we
recognized an unrealized gain of $8.7 million from the
change in the fair value of commodity derivatives. A 10%
increase in the NYMEX floating prices would have resulted in a
$2.1 million decrease in the December 31, 2007 fair
value recorded on our balance sheet, and a corresponding
increase to loss on commodity derivatives in our statement of
operations.
Share-based
compensation
Prior to January 1, 2006, we accounted for stock option
awards granted under our 2003 Stock Option Plan in accordance
with the recognition and measurement provisions of Accounting
Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees and related Interpretations, as
permitted by Statement of Financial Accounting Standards
No. 123, Accounting for Stock-Based Compensation
(“SFAS No. 123”). Share-based employee
compensation expense was not recognized in the our consolidated
statements of operations prior to January 1, 2006, as all
stock option awards granted had an exercise price equal to or
greater than the estimated fair market value of the common stock
on the date of the grant. As permitted by
SFAS No. 123, we reported in the notes to our
consolidated financial statements the pro forma disclosures
presenting results and earnings (loss) per share as if we had
used the fair value recognition provisions of
SFAS No. 123. Share-based
31
compensation related to non-employees and modifications of
options granted were accounted for based on the fair value of
the related stock or options in accordance with
SFAS No. 123 and its interpretations.
Effective January 1, 2006, we adopted the provisions of
Statement of Financial Accounting Standards No. 123
(revised 2004), Share-Based Payment
(“SFAS No. 123(R)”), which requires the
measurement and recognition of compensation expense for all
share-based payment awards to employees and directors based on
estimated fair values. We adopted SFAS No. 123(R)
using the modified prospective transition method. In accordance
with the modified prospective application provisions of
SFAS No. 123(R), compensation cost for the portion of
awards that were outstanding as of January 1, 2006, for
which the requisite service was not rendered, are recognized as
the requisite service is rendered, based on the grant date fair
value estimated in accordance with the provisions of
SFAS No. 123(R). Additionally, compensation costs for
awards granted after January 1, 2006 are recognized over
the requisite service period based on the grant-date fair value.
In accordance with the modified prospective transition method,
our consolidated financial statements for prior periods have not
been restated to reflect the impact of SFAS No. 123(R).
The fair value of each option granted was estimated using an
option-pricing model with the following weighted average
assumptions during the year ended December 31, 2007. There
were no options granted during the years ended December 31,
2006 and 2005:
|
|
|
|
|
Expected dividends
|
|
|
—
|
|
Expected volatility
|
|
|
68%
|
|
Risk-free interest rate
|
|
|
3.9%
|
|
Expected life
|
|
|
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.
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 No. 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 have been immaterial to share-based
compensation expense for the year ended December 31, 2007.
Recent
accounting pronouncements
In March 2008, the Financial Accounting Standards Board
(“FASB”) issued Statement of Financial Accounting
Standard No. 161, Disclosures about Derivative Instruments
and Hedging Activities, an amendment of FASB Statement
No. 133 (“SFAS 161”). SFAS 161 amends
and expands the disclosure requirements of FASB Statement
No. 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 No. 133 and its related
interpretations, and (iii) how derivative instruments and
related hedged items affect and entity’s 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.
32
In December 2007, FASB issued Statement of Financial Accounting
Standards No. 141 (revised 2007), Business Combinations
(“SFAS No. 141(R)”).
SFAS No. 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 No. 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 No. 160, Noncontrolling Interests
in Consolidated Financial Statements, an Amendment of ARB
No. 51 (“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 parent’s 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.
In September 2006, Statement of Financial Accounting Standards
No. 157, Fair Value Measurements
(“SFAS 157”), was issued. SFAS 157
provides guidance for using fair value to measure assets and
liabilities. It applies whenever other standards require or
permit assets or liabilities to be measured at fair value, but
it does not expand the use of fair value in any new
circumstances. The provisions of SFAS 157 are effective for
financial statements issued for fiscal years beginning after
November 15, 2007. The effect of adopting SFAS 157 is
not expected to have a significant effect on our reported
financial position or earnings, but it will require additional
disclosure regarding our derivative instruments when adopted.
In February 2007, SFAS No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities -Including
an Amendment of FASB Statement No. 115
(“SFAS 159”), was issued. SFAS 159
permits an entity to choose to measure many financial
instruments and certain other items at fair value. The fair
value option established by SFAS 159 permits all entities
to choose to measure eligible items at fair value at specified
election dates. Unrealized gains and losses on items for which
the fair value option has been elected are to be recognized in
earnings at each subsequent reporting date. SFAS 159 is
effective for financial statements issued for fiscal years
beginning after November 15, 2007. The effect of adopting
SFAS 159 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, 2007, 2006 or
2005. 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
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 management and key employees. Granting of awards may increase
our general and administrative expenses subject to the size and
timing of the grants. See Note 5 to our consolidated
financial statements.
Public
company expenses
Our general and administrative expenses increased in connection
with the completion of our IPO and as a result of us operating
as a public company. This increase consisted of legal and
accounting fees and additional expenses associated with
compliance with the Sarbanes Oxley Act of 2002 and other
regulations. We anticipate
33
that our ongoing general and administrative expenses also will
increase as a result of being a publicly traded company. This
increase will be due primarily to the cost of accounting support
services, filing annual and quarterly reports with the SEC,
investor relations, directors’ fees, directors’ and
officers’ insurance and registrar and transfer agent fees.
As a result, we believe that our general and administrative
expenses for future periods will increase significantly.
Results
of operations
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 expenses
|
|
$
|
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
34
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 are entering into a mix of swaps and collars in
2007, which results in less volatility to the results of
operations.
Lease operating expense. Our lease operating
expenses 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 lease operating expense
was the release in mid-2006 of one of our seven rented
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 management’s 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
(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.
35
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 4.1% 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 under the contribution
agreement on November 14, 2007.
Years
ended December 31, 2006 and 2005
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
Revenues (in thousands):
|
|
|
|
|
|
|
|
|
Gas
|
|
$
|
41,851
|
|
|
$
|
40,085
|
|
Oil
|
|
|
4,821
|
|
|
|
3,179
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales
|
|
$
|
46,672
|
|
|
$
|
43,264
|
|
Realized gain on commodity derivatives
|
|
|
6,222
|
|
|
|
(2,924
|
)
|
|
|
|
|
|
|
|
|
|
Total oil and gas sales including derivative impact
|
|
|
52,894
|
|
|
|
40,340
|
|
Production:
|
|
|
|
|
|
|
|
|
Gas (MMcf)
|
|
|
6,282
|
|
|
|
4,668
|
|
Oil (MBbls)
|
|
|
77
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
Total (MMcfe)
|
|
|
6,744
|
|
|
|
5,012
|
|
Average prices:
|
|
|
|
|
|
|
|
|
Gas (per Mcf)
|
|
$
|
6.66
|
|
|
$
|
8.59
|
|
Oil (per Bbl)
|
|
|
62.65
|
|
|
|
55.54
|
|
|
|
|
|
|
|
|
|
|
Total (per Mcfe)
|
|
$
|
6.92
|
|
|
$
|
8.63
|
|
Realized gain on commodity derivatives (per Mcfe)
|
|
|
0.92
|
|
|
|
(0.58
|
)
|
|
|
|
|
|
|
|
|
|
Total per Mcfe including derivative impact
|
|
$
|
7.84
|
|
|
$
|
8.05
|
|
Costs and expenses (per Mcfe):
|
|
|
|
|
|
|
|
|
Lease operating expenses
|
|
$
|
0.58
|
|
|
$
|
0.58
|
|
Severance and production taxes
|
|
|
0.26
|
|
|
|
0.39
|
|
Exploration
|
|
|
0.24
|
|
|
|
0.15
|
|
Impairment of non-producing properties
|
|
|
0.08
|
|
|
|
—
|
|
General and administrative
|
|
|
0.36
|
|
|
|
0.53
|
|
Depletion, depreciation and amortization
|
|
|
2.16
|
|
|
|
1.60
|
|
Oil and gas sales. Oil and gas sales increased
$3.4 million, or 7.9%, for the year ended December 31,
2006 to $46.7 million from $43.3 million for the year
ended December 31, 2005. The increase in sales principally
resulted from a 34.6% increase in production, as we drilled and
completed 81 gross (53.3 net) wells in 2006. The effects of
increased production were offset by a decrease in price. The
average price before the effect of commodity derivatives
decreased $1.71 per Mcfe, or 19.8%, from $8.63 per Mcfe in 2005
to $6.92 per Mcfe in 2006 as the 2005 period included the
effects of the spike in gas prices after Hurricane Katrina and
Hurricane Rita. Gas sales represented 89.7% of the total oil and
gas sales in 2006 compared to 92.7% in 2005.
Commodity derivative activities. Realized
gains from our commodity derivative activity increased our
earnings $6.2 million for the year ended December 31,
2006. In comparison, realized losses from our commodity
derivative activity decreased our earnings $2.9 million for
the year ended December 31, 2005. The change in fair value
of commodity derivatives was an $8.7 million increase
during the year ended
36
December 31, 2006 and a $4.2 million decrease during
the year ended December 31, 2005. During the years ended
December 31, 2005 and 2006, we used gas swaps to mitigate
commodity price risk. During 2005, commodity prices tended to be
higher than the notional prices specified in our swap
agreements, which resulted in a loss to us. In contrast, during
2006, commodity prices tended to be lower than the prices
specified in our swap agreements, which resulted in a gain to us.
Lease operating expense. Our lease operating
expenses increased $1.0 million, or 33.7%, for the year
ended December 31, 2006 to $3.9 million from
$2.9 million for the year ended December 31, 2005.
This increase primarily was the result of a $765,000 increase in
ad valorem taxes and from increased pumper costs of $200,000
from the continued development of the Ozona Northeast properties.
Severance and production taxes. Our production
taxes decreased $239,000, or 12.1%, for the year ended
December 31, 2006 to $1.7 million from
$2.0 million for the year ended December 31, 2005. The
decrease in production taxes is a function of increased oil and
gas revenues that were more than offset by refunds received
applicable to prior years. 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. During 2005, we were still awaiting
approvals for abatements on several of our Ozona Northeast
wells. We received such approvals during 2006, which resulted in
the refunds mentioned above.
Exploration and impairment of non-producing
properties. Our exploration costs increased
$907,000 to $1.6 million for the year ended
December 31, 2006 from $734,000 for the year ended
December 31, 2005. 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.
The 2005 period included dry hole costs of $902,000 from Pecos
County and $285,000 from the same well mentioned above in Ozona
Northeast. Additionally, the 2005 period included the recoupment
of $564,000 of geological evaluation costs from a participant in
the Pecos County project. The balance of the 2005 expense is
geological and geophysical costs mostly attributable to Ozona
Northeast.
Our impairment of non-producing properties of $558,000 in 2006
arose from the abandonment of our leasehold position in Pecos
County. As a result of the abandonment, we no longer anticipate
incurring any costs related to this area.
General and administrative. Our general and
administrative expenses decreased $243,000, or 9.1%, to
$2.4 million for the year ended December 31, 2006 from
$2.7 million for the year ended December 31, 2005. The
decrease in general and administrative expense was principally
due to the accrual in 2005 of bonuses totaling approximately
$800,000 that did not recur in 2006, offset by increases in 2006
for professional fees, the number of employees and increases in
their compensation and benefits. Additionally, operating
overhead recoveries in 2006 were $514,000 as compared to
$408,000 in 2005.
Depletion, depreciation and amortization
(DD&A). Our DD&A expense increased
$6.5 million, or 81.6%, to $14.5 million for the year
ended December 31, 2006 from $8.0 million for the year
ended December 31, 2005. Our DD&A expense per Mcfe
produced increased by $0.56, or 35.0%, to $2.16 per Mcfe for the
year ended December 31, 2006, as compared to $1.60 per Mcfe
for the year ended December 31, 2005. This increase was
primarily attributable to increased production and increased oil
and gas property costs in 2006.
Interest expense, net. Our interest expense
increased $3.0 million, or 375%, to $3.8 million for
the year ended December 31, 2006 from $802,000 for the year
ended December 31, 2005. This significant increase was a
function of increased borrowings under our revolving credit
facility and an increase in interest rates during 2006. Interest
rates attributable to amounts outstanding under our revolving
credit facility amounted to 6.75% at December 31, 2005,
compared with 7.75% at December 31, 2006.
Income taxes. Income taxes increased
$4.8 million, or 67.3%, to $11.8 million for the year
ended December 31, 2006 from $7.0 million for the year
ended December 31, 2005. Income taxes increased consistent
with our income before tax, offset by a decrease in our
effective tax rates, which amounted to 36.8% and 35.7% for the
years ended December 31, 2005 and 2006, respectively. Our
effective tax rate
37
decreased due primarily to a change in the tax law in the State
of Texas which changed the tax from 4.5% of net income to 1% of
our “margin,” as defined in the new law. Based on this
change in the Texas tax law, we reduced our deferred tax
liability by approximately $1.1 million for the year ended
December 31, 2006.
Liquidity
and capital resources
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
|
|
$
|
51.1
|
|
Repurchase of stock held by selling stockholder
|
|
$
|
22.5
|
|
For the year ended December 31, 2007, we used the
$73.6 million proceeds from the IPO, $84.3 million of
net proceeds from bank and convertible debt borrowings and cash
flow from operations of $30.7 million to fund:
|
|
|
|
•
|
$51.8 million of capital expenditures related to our
drilling program activities,
|
|
|
•
|
$917,000 investment in a Canadian-based private exploration
company,
|
|
|
•
|
repayment of $111.9 million on our credit facility,
|
|
|
•
|
payment of $1.5 million of offering costs related to our
IPO, and
|
|
|
•
|
repurchase of $22.5 million of stock held by the selling
stockholder.
|
For the year ended 2006, we used $34.3 million of cash flow
from operations and $3.5 million of proceeds from
borrowings under a note with one of our stockholders and our
revolving credit facility and available cash to fund
$59.4 million for our drilling program and
$1.3 million to repurchase shares.
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 initial public offering.
For the year ended December 31, 2006, our primary sources
of cash were from financing and operating activities.
Approximately $18.2 million from borrowings 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 drilling program, the acquisition of another working
interest in the Ozona Northeast field and $1.3 million to
repurchase shares and cancel stock options.
For the year ended December 31, 2005, cash flow from
operations of $40.6 million, borrowings under our revolving
credit facility of $29.3 million and $3.0 million from
the issuance of common stock provided the funds to drill
additional wells in the Ozona Northeast field.
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 2006 and 2007, our cash flows
from operations decreased due mostly to lower oil and gas sales
and higher general and administrative expenses during the year
ended December 31, 2007. In comparing 2005 and 2006, our
cash
38
flows from operations declined slightly due to a
$6.2 million decrease in working capital components
partially offset by the increase in oil and gas sales in 2006.
The following table summarizes our sources and uses of funds for
the periods noted:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
(In thousands)
|
|
|
|
|
|
Cash flows provided by operating activities
|
|
$
|
30,746
|
|
|
$
|
34,305
|
|
|
$
|
40,588
|
|
Cash flows used in investing activities
|
|
|
(52,940
|
)
|
|
|
(59,384
|
)
|
|
|
(72,224
|
)
|
Cash flows provided by financing activities
|
|
|
22,062
|
|
|
|
26,771
|
|
|
|
32,199
|
|
Effect of Canadian exchange rate
|
|
|
6
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents
|
|
$
|
(126
|
)
|
|
$
|
1,692
|
|
|
$
|
563
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
activities
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.
Net cash provided by operating activities decreased from
$40.6 million in 2005 to $34.3 million in 2006. In
comparing 2005 and 2006, our cash flows from operations declined
$6.3 million in part due to a decrease in working capital
components partially offset by the increase in oil and gas sales
and net income in 2006 from our continued development of the
Ozona Northeast field in West Texas.
Investing
activities
The majority of our cash flows used in investing activities for
the years ended 2007 and 2006 have been used for the continued
development of the Ozona Northeast and Cinco Terry fields. The
following is a summary of capital expenditures by prospect (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Exploration and development costs:
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
$
|
27,986
|
|
|
$
|
52,303
|
|
Cinco Terry
|
|
|
10,586
|
|
|
|
3,176
|
|
North Bald Prairie
|
|
|
4,974
|
|
|
|
—
|
|
El Vado East
|
|
|
—
|
|
|
|
—
|
|
Boomerang
|
|
|
2,496
|
|
|
|
—
|
|
Northeast British Columbia
|
|
|
1,235
|
|
|
|
—
|
|
Lease acquisition, geological, geophysical and other(1)
|
|
|
4,920
|
|
|
|
3,873
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
52,197
|
|
|
$
|
59,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes $3.0 million for undeveloped leaseholds in our
British Columbia prospect and $2.5 million for undeveloped
leaseholds in our El Vado East prospect during the year ended
December 31, 2007. Additionally, we recovered
$1.4 million of our initial investment in the Boomerang
prospect acreage from the original owner’s election to
participate in the project during the year ended
December 31, 2007. Includes $3.5 million that was
invested in the undeveloped leaseholds in our Boomerang prospect
for the year ended December 31, 2006. |
The majority of our cash flows used in investing activities for
the year ended December 31, 2005 were used for the
development of the Ozona Northeast field.
We have established an exploratory and development budget of
$64.3 million 2008. Our budgets are established based on
expected volumes to be produced and commodity prices.
39
Financing
activities
We borrowed $84.3 million under convertible notes and our
revolving credit facility in 2007 as compared to
$119.5 million net 2006. We repaid a total of
$111.9 million and $101.4 million of amounts
outstanding under our credit facility for the years ended
December 31, 2007 and 2006, respectively. In addition, we
spent $1.3 million in the first six months of 2006 to
purchase common stock and related options from a former
employee. For 2005, we borrowed $103.8 million from our
revolving credit facility, repaid $74.5 million under the
facility and received $3.0 million from the issuance of
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 were used as follows (in millions):
|
|
|
|
|
Repayment of revolving credit facility
|
|
$
|
51.1
|
|
Repurchase of stock held by selling stockholder
|
|
$
|
22.5
|
|
During 2006, we sold approximately $6.5 million of common
stock. These proceeds were primarily used to fund the
acquisition of our Boomerang prospect and drilling costs for our
Cinco Terry project.
In February 2007, we entered into an amended and restated
$100 million revolving credit facility with The Frost
National Bank and JPMorgan Chase, NA. As of December 31,
2007, we had no outstanding balance under the credit facility
with a borrowing base of $75 million. We currently have
$13.8 million in long-term debt outstanding under our
revolving credit facility. In January 2008, we entered into a
$200 million revolving credit facility that superseded and
terminated the prior $100 million revolving credit
facility. The borrowing base under the new credit agreement
remained $75 million at February 29, 2008. The
borrowing base is subject to adjustment at least twice each
year. The assessment by the bank petroleum engineers is based on
their evaluation of the future cash flows from proved oil and
gas reserves using the bank’s pricing parameters.
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 and borrowings under
our revolving credit facility will finance substantially all of
our anticipated drilling, exploration and capital needs in 2008.
We may also use our revolving credit facility for possible
acquisitions, temporary working capital needs and any expansion
of our drilling program through 2008.
40
Future
capital expenditures for 2008
The following table summarizes information regarding our
historical 2007 and estimated 2008 capital expenditures. We will
be required to meet our needs from our internally generated cash
flow, debt financings and equity financings. The estimated
capital expenditures are subject to change depending upon a
number of factors, including the results of our development and
exploration efforts, the availability of sufficient capital
resources to us and other participants for drilling prospects,
economic and industry conditions at the time of drilling,
including prevailing and anticipated prices for oil and gas and
the availability of drilling rigs and crews, our financial
results and the availability of leases on reasonable terms and
our ability to obtain permits for the drilling locations.
|
|
|
|
|
|
|
|
|
|
|
Estimated
|
|
|
Historical
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands)
|
|
|
Capital expenditures:
|
|
|
|
|
|
|
|
|
Ozona Northeast
|
|
|
|
|
|
|
|
|
Acquisition of Neo Canyon
|
|
$
|
—
|
|
|
$
|
60,225
|
|
Development
|
|
|
29,500
|
|
|
|
27,986
|
|
Cinco Terry
|
|
|
10,900
|
|
|
|
10,586
|
|
North Bald Prairie
|
|
|
14,400
|
|
|
|
4,974
|
|
El Vado East
|
|
|
3,600
|
|
|
|
—
|
|
Boomerang
|
|
|
1,800
|
|
|
|
2,496
|
|
Northeast British Columbia
|
|
|
3,200
|
|
|
|
1,235
|
|
Lease acquisition, geological, geophysical and other
|
|
|
900
|
|
|
|
4,920
|
|
|
|
|
|
|
|
|
|
|
Total capital expenditures
|
|
$
|
64,300
|
|
|
$
|
112,422
|
|
|
|
|
|
|
|
|
|
|
Credit
facility
In February 2007, we entered into an amended and restated
$100 million revolving credit facility with The Frost
National Bank and JPMorgan Chase, NA. In January 2008, we
entered into a new $200 million revolving credit facility
with The Frost National Bank and JPMorgan Chase, NA that
superseded and terminated the prior revolving credit facility.
The availability of funds under our revolving credit facility is
subject to a borrowing base which was initially set at, and
currently is, $75 million. The borrowing base will be
redetermined every six months or, upon the election by us or the
bank, one additional time each calendar year.
Our revolving credit facility provides for interest on
outstanding amounts to accrue at a rate calculated, at our
option, at either (i) the base rate, which is the
bank’s prime rate, or (ii) the sum of the LIBOR plus a
margin which ranges from 1.25% to 2.0% per annum, as applicable,
as amounts outstanding under our revolving credit facility
increase as a percentage of the borrowing base. In addition, we
pay an annual commitment fee of 0.375% of non-utilized
borrowings available under our revolving credit facility.
We are subject to a financial covenant requiring maintenance of
a minimum modified ratio of current assets to current
liabilities. In addition, we are subject to covenants
restricting 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.
Loans under our revolving credit facility are secured by first
priority liens on substantially all of our West Texas assets
including a guarantee by two of our subsidiaries. All
outstanding amounts under our revolving credit facility are due
and payable in July 2010.
41
Contractual
commitments
In April 2007, we signed a five-year lease for approximately
13,000 square feet of new office space in Fort Worth,
Texas. In January 2008, we began rent payments of approximately
$20,000 per month, including common area expenses. We have a
lease for our prior space in Fort Worth, Texas that expires
in May 2009. Our obligation under this lease is approximately
$119,000 per year. At December 31, 2007, we had signed
subleases for approximately two-thirds of our prior office
space. In February 2008, we subleased the remainder of our prior
office space.
The following table summarizes these commitments as of
December 31, 2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
Contractual Obligations
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Operating lease obligations(1)
|
|
|
1,442
|
|
|
|
374
|
|
|
|
841
|
|
|
|
227
|
|
|
|
—
|
|
Asset retirement obligations
|
|
|
548
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
548
|
|
Employment agreements with executive officers and other key
personnel(2)
|
|
|
1,300
|
|
|
|
1,300
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,290
|
|
|
$
|
1,674
|
|
|
$
|
841
|
|
|
$
|
227
|
|
|
$
|
548
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Operating lease obligations are for office space. We will
receive $165,000 for office space that has been subleased from
January 2008 through May 2009. |
|
(2) |
|
These agreements 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 $1.3 million at
December 31, 2007. |
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, 2007, the off-balance sheet
arrangements and transactions that we have entered into include
undrawn letters of credit amounting to $3.0 million,
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.
|
|
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 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
We enter into financial swaps and collars to hedge future oil
and gas production to mitigate portions of the risk of market
price fluctuations.
To designate a derivative as a cash flow hedge, we document at
the commodity derivative’s inception our assessment as to
whether the derivative will be highly effective in offsetting
expected changes in cash flows from the item hedged. This
assessment, which is updated at least quarterly, is generally
based on the most recent relevant historical correlation between
the derivative and the item hedged. The ineffective portion of
the
42
commodity derivative, if any, is calculated as the difference
between the change in fair value of the derivative and the
estimated change in cash flows from the item hedged.
If, during a commodity derivative’s term, we determine the
commodity derivative is no longer highly effective, commodity
derivative accounting is prospectively discontinued and any
remaining unrealized gains or losses on the effective portion of
the derivative are reclassified to earnings when the underlying
transaction occurs. If it is determined that the designated
commodity derivative transaction is not likely to occur, any
unrealized gains or losses are recognized immediately in the
consolidated statements of income as a derivative fair value
gain or loss.
Currently, we have the following commodity derivative positions
outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
$/MMBtu
|
|
Period
|
|
Monthly
|
|
|
Total
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Fixed
|
|
|
NYMEX — Henry Hub
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costless collars 2008
|
|
|
186,000
|
|
|
|
2,230,000
|
|
|
$
|
7.50
|
|
|
$
|
11.45
|
|
|
|
|
|
Costless collars 2008
(3rd
quarter)
|
|
|
100,000
|
|
|
|
300,000
|
|
|
$
|
7.00
|
|
|
$
|
9.10
|
|
|
|
|
|
Costless collars 2008
(2nd —
4th
quarter)
|
|
|
200,000
|
|
|
|
1,800,000
|
|
|
$
|
9.00
|
|
|
$
|
12.20
|
|
|
|
|
|
Costless collars 2009
|
|
|
180,000
|
|
|
|
2,160,000
|
|
|
$
|
7.50
|
|
|
$
|
10.50
|
|
|
|
|
|
Costless collars 2009
|
|
|
130,000
|
|
|
|
1,560,000
|
|
|
$
|
8.50
|
|
|
$
|
11.70
|
|
|
|
|
|
Fixed price swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd
quarter 2008
|
|
|
100,000
|
|
|
|
300,000
|
|
|
|
|
|
|
|
|
|
|
$
|
8.10
|
|
4th
quarter 2008
|
|
|
100,000
|
|
|
|
300,000
|
|
|
|
|
|
|
|
|
|
|
$
|
8.63
|
|
WAHA differential
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps 2008
|
|
|
186,000
|
|
|
|
2,230,000
|
|
|
|
|
|
|
|
|
|
|
|
(0.69
|
)
|
Fixed price swaps 2008
(2nd —
4th
quarter)
|
|
|
100,000
|
|
|
|
900,000
|
|
|
|
|
|
|
|
|
|
|
|
(0.67
|
)
|
Fixed price swaps 2009
|
|
|
200,000
|
|
|
|
2,400,000
|
|
|
|
|
|
|
|
|
|
|
|
(0.61
|
)
|
At December 31, 2007 and December 31, 2006, the fair
value of our open derivative contracts was an asset of
approximately $868,000 and $4.5 million, respectively.
We have reviewed the financial strength of our commodity
derivative counterparty and believe our credit risk to be
minimal. Our commodity derivative counterparty is a participant
in our credit facility and the collateral for the outstanding
borrowings under our revolving credit facility is used as
collateral for our commodity derivatives.
|
|
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.
|
|
Item 9A(T).
|
Controls
and Procedures.
|
Disclosure
controls and procedures
Our management, with the participation of our 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, 2007. Based on
this evaluation, our Chief Executive Officer and Chief Financial
Officer have concluded that, as of December 31, 2007, 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 SEC’s rules and forms, and
(2) accumulated and communicated to our
43
management, including our Chief Executive Officer and Chief
Financial Officer, as appropriate to allow timely decisions
regarding required disclosure.
Internal
control over financial reporting
No changes to our internal control over financial reporting
occurred during the year ended December 31, 2007 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). The SEC’s rules under
Section 404 of the Sarbanes-Oxley Act of 2002 become
applicable to us beginning with our Annual Report on
Form 10-K
for the year ending December 31, 2008 to be filed in the
first quarter of 2009. We cannot give any assurance, however,
that our internal controls will be effective when
Section 404 becomes applicable to us. Ineffective internal
controls could cause investors to lose confidence in our
reported financial information and could result in a lower
trading price for our securities.
This report on
Form 10-K
does not include a report of management’s assessment
regarding internal control over financial reporting or an
attestation report of our registered public accounting firm due
to a transition period established by rules of the SEC for newly
public companies.
|
|
Item 9B.
|
Other
Information.
|
None.
44
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance.
|
Our executive officers and directors and their ages and
positions as of March 14, 2008, are as follows:
|
|
|
|
|
|
|
Name
|
|
Age
|
|
Position
|
|
J. Ross Craft
|
|
|
51
|
|
|
President, Chief Executive Officer and Class III Director
|
Steven P. Smart
|
|
|
53
|
|
|
Executive Vice President, Chief Financial Officer and Treasurer
|
J. Curtis Henderson
|
|
|
45
|
|
|
Executive Vice President and General Counsel
|
Glenn W. Reed
|
|
|
56
|
|
|
Senior Vice President — Operations
|
Ralph P. Manoushagian
|
|
|
56
|
|
|
Senior Vice President — Land
|
Bryan H. Lawrence
|
|
|
65
|
|
|
Chairman, Class III Director
|
James H. Brandi
|
|
|
59
|
|
|
Class II Director
|
James C. Crain
|
|
|
59
|
|
|
Class II Director
|
Sheldon B. Lubar
|
|
|
78
|
|
|
Class I Director
|
Christopher J. Whyte
|
|
|
51
|
|
|
Class I Director
|
J. Ross Craft has been our President and Chief Executive
Officer and a member of our board of directors since our
inception in September 2002. Before Approach, Mr. Craft
co-founded Athanor Resources Inc., an international exploration
and production company with operations in the United States and
Tunisia, in 1998 and was its Executive Vice President from 1998
until its merger with Nuevo Energy Company in September 2002.
From 1988 to 1997, Mr. Craft served in various positions
with American Cometra Inc., an independent exploration and
production company with operations in the United States,
including Vice President — Operations from 1995 to
1997. American Cometra was sold in two parts, to Range Resources
in 1995 and Pioneer Natural Resources in 1997. Mr. Craft
has 27 years of experience in the oil and gas industry.
Mr. Craft, who holds a B.S. in Petroleum Engineering from
Texas A&M University, is a registered Professional Engineer
licensed in the State of Texas. In addition to membership in the
Society of Petroleum Engineers, Mr. Craft is a member of
the Texas Oil and Gas Association and Independent Petroleum
Association of America. Mr. Craft has served on the board
of the Fort Worth chapter of the Society of Petroleum
Engineers as well as on the board of the Fort Worth
Petroleum Engineers Club where his last position was President.
In addition to the above, Mr. Craft is an Eagle Scout.
Mr. Craft is the
brother-in-law
of J. Curtis Henderson, our Executive Vice President and General
Counsel.
Steven P. Smart has been our Treasurer since our
inception in September 2002. Mr. Smart was named Vice
President — Finance in August 2005, and promoted to
Executive Vice President and Chief Financial Officer in June
2007. From 2000 to 2002, Mr. Smart was Controller and
Treasurer of Prize Energy Corp., a public exploration and
production company. From 1998 to 2000, Mr. Smart was a
Senior Manager in the Energy Industry group at Arthur Andersen
LLP. Prior to 2000, Mr. Smart served in senior executive
financial positions with several public and private oil and gas
companies, including Magnum Hunter Resources Inc. and Saxon Oil
Co. Mr. Smart began his career in public accounting with
Deloitte & Touche (formerly Touche Ross).
Mr. Smart has more than 30 years of experience in both
public and private companies in the oil and gas industry.
Mr. Smart, who holds a B.B.A. in Accounting from Angelo
State University, is a Certified Public Accountant with an
active license.
J. Curtis Henderson joined us in February 2007 as
Executive Vice President and General Counsel. From 2005 to 2007,
Mr. Henderson served as President and Chief Executive
Officer of Coterie Capital Partners, Ltd., a private equity
partnership in Dallas, Texas. From 1998 to 2005,
Mr. Henderson served as General Counsel of Nucentrix
Broadband Networks, Inc., a public broadband wireless
telecommunications company based in Dallas. While he was at
Nucentrix, Mr. Henderson oversaw the sale of that company
to an affiliate of Nextel Communications Inc. under
Section 363 of the United States Bankruptcy Code in 2004.
Mr. Henderson began his career as a lawyer in the corporate
and securities section of Locke Lord Bissell & Liddell
(formerly
45
Locke Purnell Rain Harrell). Mr. Henderson has over
20 years experience in public and private securities,
mergers and acquisitions, corporate finance and regulatory
affairs. Mr. Henderson holds a B.A. in Political Science
from Austin College and a J.D. from Washington and Lee
University School of Law. Mr. Henderson is the
brother-in-law
of J. Ross Craft, our Chief Executive Officer and President.
Glenn W. Reed has been our Senior Vice
President — Operations since June 2007. Mr. Reed
served as our Vice President — Operations from our
inception in September 2002 to June 2007. Mr. Reed was
Manager of Operations for Athanor Resources Inc. from 1999 to
2002, where he was responsible for petroleum engineering and
operations before Athanor was sold to Nuevo Energy Company in
September 2002. From 1988 to 1999, Mr. Reed supervised
operations for American Cometra. Mr. Reed, who holds a B.S.
in Petroleum Engineering from Texas Tech University, is a
registered Professional Engineer licensed in Texas and has
28 years of experience in the oil and gas industry.
Ralph P. Manoushagian has been our Senior Vice
President — Land since June 2007.
Mr. Manoushagian joined us in 2004 as Land Manager. In
2003, Mr. Manoushagian worked as an independent landman.
From 2001 to 2003, Mr. Manoushagian was the President of
Hudco Fuels, a privately owned fuel distributorship.
Mr. Manoushagian has been an active landman and oil and gas
operator for 30 years. Mr. Manoushagian, who holds a
B.B.A. in Finance from the University of North Texas, has been a
Certified Professional Landman since 1988. Mr. Manoushagian
is a director of the First Financial Bank of Southlake, Texas.
He previously served as a director and Vice President of the
Texas Independent Producers and Royalty Owners and as a director
of the Texas Alliance of Energy Producers.
Bryan H. Lawrence has been a member of our board of
directors since 2002. Mr. Lawrence is a founder and Senior
Manager of Yorktown Partners LLC, the manager of the Yorktown
group of investment partnerships, which make investments in
companies in the energy industry. The Yorktown group of
investment partnerships were formerly affiliated with the
investment firm of Dillon, Read & Co. Inc., where
Mr. Lawrence had been employed since 1966, serving as a
Managing Director until the merger of Dillon Read with SBC
Warburg in September 1997. Mr. Lawrence also serves as a
director of Crosstex Energy, Inc. and Crosstex Energy GP, LLC,
midstream natural gas companies; Hallador Petroleum Company, an
independent company engaged in the production of coal and the
exploration and production of oil and natural gas; the general
partner of Star Gas Partners, L.P., a home heating oil
distributor and services provider; Winstar Resources, a public
Canadian oil and gas company; Ellora Energy Inc., an independent
oil and gas company; and certain non-public companies in the
energy industry in which the Yorktown group of investment
partnerships hold equity interests. Mr. Lawrence is a
graduate of Hamilton College and also has an M.B.A. from
Columbia University.
James H. Brandi joined us as a director in June
2007. Since November 2005, Mr. Brandi has been a
partner at Hill Street Capital, a private investment and
financial advisory firm. From 2000 until November 2005,
Mr. Brandi was a Managing Director at UBS Securities, LLC,
where he was the Deputy Global Head of the Energy and Power
Group. Prior to 2000, Mr. Brandi was a Managing Director at
Dillon, Read & Co. Inc. and later its successor firm,
UBS Warburg, concentrating on transactions in the energy and
consumer goods areas. Mr. Brandi serves on the boards of
Energy East Corporation, a utility holding company, and
Armstrong Land Company, LLC, a coal reserves owning company.
Mr. Brandi is a trustee of The Kenyon Review and a former
trustee of Kenyon College. Mr. Brandi holds a B.A. in
History from Yale University and an M.B.A. from Harvard Business
School and attended Columbia Law School as a Harlan Fiske Stone
Scholar.
James C. Crain joined us as a director in June
2007. Mr. Crain has been involved in the energy
industry for over 30 years, both as an attorney and as an
executive officer. Since 1984, Mr. Crain has been an
officer of Marsh Operating Company, an investment management
company focusing on energy investing, including his current
position of President which he has held since 1989.
Mr. Crain has served as general partner of Valmora
Partners, L.P., a private investment partnership that invests in
the oil and gas sector, among others, since 1997. Prior to
joining Marsh in 1984, Mr. Crain was a partner in the law
firm of Jenkens & Gilchrist, where he headed the
firm’s energy section. Mr. Crain currently is a
director of Crosstex Energy, Inc. and Crosstex Energy GP, LLC,
midstream natural gas companies, and GeoMet, Inc., a coalbed
methane natural gas
46
exploration and production company. Mr. Crain holds a
B.B.A., an M.P.A. and a J.D. from the University of Texas at
Austin.
Sheldon B. Lubar joined us as a director in June
2007. Mr. Lubar has been Chairman of the Board
of Lubar & Co. Incorporated, a private investment and
venture capital firm he founded, since 1977. He was Chairman of
the Board of Christiana Companies, Inc., a logistics and
manufacturing company, from 1987 until its merger with
Weatherford International in 1995. Mr. Lubar is currently a
director of Crosstex Energy, Inc. and Crosstex Energy GP, LLC,
midstream natural gas companies; Weatherford International,
Inc., an energy services company; Ellora Energy Inc., an
independent oil and gas company; and the general partner of Star
Gas Partners, L.P., a home heating oil distributor and services
provider. Mr. Lubar previously held governmental
appointments under three United States Presidents, including
Commissioner of the White House Conference on Small Business
from 1979 to 1980 under President Carter, Assistant Secretary,
Housing Production and Mortgage Credit, Department of Housing
and Urban Development, Commissioner of the Federal Housing
Administration and Director of the Federal National Mortgage
Association from 1973 to 1974 under Presidents Nixon and Ford.
Mr. Lubar is a past president of the Board of Regents of
the University of Wisconsin System. Mr. Lubar holds a B.S.
in Business Administration and a J.D. from the University of
Wisconsin — Madison. Mr. Lubar was awarded an
honorary Doctor of Commercial Science degree from the University
of Wisconsin — Milwaukee.
Christopher J. Whyte has been a member of our board of
directors since June 2007. Mr. Whyte has been President,
Chief Executive Officer and a director of PetroSantander Inc.,
which owns and operates oil and gas production in Colombia,
Kansas and Brazil, since 1995. Mr. Whyte holds a B.A. from
the University of Pittsburgh.
Additional information required under Item 10,
“Directors, Executive Officers and Corporate
Governance” will be provided in our proxy statement for our
2008 annual meeting of stockholders. 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 definitive proxy statement for our 2008 annual meeting of
stockholders to be filed with the SEC on or before
April 29, 2008, 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 definitive proxy
statement for our 2008 annual meeting of stockholders to be
filed with the SEC on or before April 29, 2008, which is
incorporated herein by reference.
47
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,
2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c)
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
|
|
|
|
Securities
|
|
|
|
(a)
|
|
|
|
|
|
Remaining Available
|
|
|
|
Number of
|
|
|
|
|
|
for Future Issuance
|
|
|
|
Securities to be
|
|
|
(b)
|
|
|
Under Equity
|
|
|
|
Issued Upon
|
|
|
Weighted-Average
|
|
|
Compensation Plans
|
|
|
|
Exercise of
|
|
|
Exercise Price of
|
|
|
(Excluding
|
|
|
|
Outstanding
|
|
|
Outstanding
|
|
|
Securities
|
|
|
|
Options, Warrants
|
|
|
Options, Warrants
|
|
|
Reflected in Column
|
|
|
|
and Rights
|
|
|
and Rights
|
|
|
(a))
|
|
|
Plan category:
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation plans approved by stockholders
|
|
|
479,991
|
|
|
$
|
7.07
|
|
|
|
1,513,559
|
|
Equity compensation plans not approved by stockholders
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
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 2008
annual meeting of stockholders to be filed with the SEC on or
before April 29, 2008, which is 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 2008
annual meeting of stockholders to be filed with the SEC on or
before April 29, 2008, 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 56 for a
description of the exhibits filed as part of this report.
48
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
earth’s 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
well’s 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.
49
MBbls. Thousand barrels of oil or other liquid
hydrocarbons.
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.
MMBbls. Million barrels of oil or other liquid
hydrocarbons.
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.
50
(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 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 or “PUDs.” 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
estimated future net revenues from proved oil and gas reserves
at a date indicated 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 Securities and Exchange
Commission’s 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 future net revenues 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 reserves by estimated 2008 production of
8.3 Bcfe (based on the mid-range of company guidance as of
March 15, 2008) 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. Tcfe. Trillion cubic feet equivalent,
determined using the ratio of six Mcf of gas to one Bbl of oil,
condensate or gas liquids.
51
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 27, 2008
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 on
March 27, 2008.
|
|
|
|
|
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
Report of
Independent Registered Public Accounting Firm
To the Board of Directors
Approach Resources Inc.
Fort Worth, Texas
We have audited the accompanying consolidated balance sheets of
Approach Resources Inc. and subsidiaries (the
“Company”) as of December 31, 2007 and 2006, and
the related consolidated statements of operations, changes in
stockholders’ equity and cash flows for each of the three
years in the period ended December 31, 2007. These
consolidated financial statements are the responsibility of the
Company’s 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. The Company is not required to
have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audits included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Company’s internal control over
financial reporting. Accordingly, we express no such opinion. 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, 2007 and 2006, and the results of their
operations and their cash flows for each of the three years in
the period ended December 31, 2007, in conformity with
accounting principles generally accepted in the United States of
America.
/s/
HEIN & ASSOCIATES LLP
Dallas, Texas
March 26, 2008
F-2
Approach
Resources Inc. and Subsidiaries
Consolidated
Balance Sheets
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
ASSETS
|
CURRENT ASSETS:
|
|
|
|
|
|
|
|
|
Cash
|
|
$
|
4,785
|
|
|
$
|
4,911
|
|
Accounts receivable:
|
|
|
|
|
|
|
|
|
Joint interest owners
|
|
|
5,272
|
|
|
|
4,813
|
|
Oil and gas sales
|
|
|
5,524
|
|
|
|
3,458
|
|
Unrealized gain on commodity derivatives
|
|
|
793
|
|
|
|
4,505
|
|
Prepaid expenses and other current assets
|
|
|
773
|
|
|
|
424
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
17,147
|
|
|
|
18,111
|
|
PROPERTIES AND EQUIPMENT:
|
|
|
|
|
|
|
|
|
Oil and gas properties, at cost, using the successful efforts
method of accounting
|
|
|
266,905
|
|
|
|
155,628
|
|
Furniture, fixtures and equipment
|
|
|
433
|
|
|
|
255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
267,338
|
|
|
|
155,883
|
|
Less accumulated depletion, depreciation and amortization
|
|
|
(36,860
|
)
|
|
|
(23,771
|
)
|
|
|
|
|
|
|
|
|
|
Net properties and equipment
|
|
|
230,478
|
|
|
|
132,112
|
|
INVESTMENT
|
|
|
917
|
|
|
|
—
|
|
UNREALIZED GAIN ON COMMODITY DERIVATIVES
|
|
|
75
|
|
|
|
—
|
|
OTHER ASSETS
|
|
|
109
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS’ EQUITY
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
5,459
|
|
|
$
|
6,246
|
|
Oil and gas sales payable
|
|
|
1,794
|
|
|
|
4,940
|
|
Accrued liabilities
|
|
|
14,764
|
|
|
|
4,235
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
22,017
|
|
|
|
15,421
|
|
NON-CURRENT LIABILITIES:
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
—
|
|
|
|
47,619
|
|
Deferred income taxes
|
|
|
26,342
|
|
|
|
17,549
|
|
Asset retirement obligations
|
|
|
548
|
|
|
|
148
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
48,907
|
|
|
|
80,737
|
|
COMMITMENTS AND CONTINGENCIES (Note 10)
|
|
|
|
|
|
|
|
|
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, 20,622,746 and 9,735,312 shares issued and
outstanding, respectively
|
|
|
206
|
|
|
|
97
|
|
Additional paid-in capital
|
|
|
166,141
|
|
|
|
43,001
|
|
Retained earnings
|
|
|
33,367
|
|
|
|
30,658
|
|
Loans to stockholders
|
|
|
—
|
|
|
|
(4,184
|
)
|
Accumulated other comprehensive income
|
|
|
105
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total stockholders’ equity
|
|
|
199,819
|
|
|
|
69,572
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders’ equity
|
|
$
|
248,726
|
|
|
$
|
150,309
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-3
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Operations
(In thousands, except shares and per-share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
REVENUES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas sales
|
|
$
|
39,114
|
|
|
$
|
46,672
|
|
|
$
|
43,264
|
|
EXPENSES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating
|
|
|
3,815
|
|
|
|
3,889
|
|
|
|
2,910
|
|
Severance and production taxes
|
|
|
1,659
|
|
|
|
1,736
|
|
|
|
1,975
|
|
Exploration
|
|
|
883
|
|
|
|
1,640
|
|
|
|
733
|
|
Impairment of non-producing properties
|
|
|
267
|
|
|
|
558
|
|
|
|
—
|
|
General and administrative
|
|
|
12,667
|
|
|
|
2,416
|
|
|
|
2,659
|
|
Depletion, depreciation and amortization
|
|
|
13,098
|
|
|
|
14,551
|
|
|
|
8,011
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses
|
|
|
32,389
|
|
|
|
24,790
|
|
|
|
16,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME
|
|
|
6,725
|
|
|
|
21,882
|
|
|
|
26,976
|
|
OTHER:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net
|
|
|
(5,219
|
)
|
|
|
(3,814
|
)
|
|
|
(802
|
)
|
Realized gain (loss) on commodity derivatives
|
|
|
4,732
|
|
|
|
6,222
|
|
|
|
(2,925
|
)
|
Change in fair value of commodity derivatives
|
|
|
(3,637
|
)
|
|
|
8,668
|
|
|
|
(4,163
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAX (BENEFIT) PROVISION
|
|
|
2,601
|
|
|
|
32,958
|
|
|
|
19,086
|
|
INCOME TAX (BENEFIT) PROVISION
|
|
|
(108
|
)
|
|
|
11,756
|
|
|
|
7,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME
|
|
$
|
2,709
|
|
|
$
|
21,202
|
|
|
$
|
12,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EARNINGS PER SHARE:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.25
|
|
|
$
|
2.26
|
|
|
$
|
1.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.24
|
|
|
$
|
2.20
|
|
|
$
|
1.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WEIGHTED AVERAGE SHARES OUTSTANDING:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
10,976,251
|
|
|
|
9,368,614
|
|
|
|
9,107,092
|
|
Diluted
|
|
|
11,183,707
|
|
|
|
9,634,912
|
|
|
|
9,107,092
|
|
See accompanying notes to these consolidated financial
statements.
F-4
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Changes in Stockholders’ Equity
for the
Years Ended December 31, 2005, 2006 and 2007
(In thousands, except 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, 2005
|
|
|
8,981,889
|
|
|
$
|
90
|
|
|
|
31,451
|
|
|
$
|
(2,602
|
)
|
|
$
|
(4,063
|
)
|
|
$
|
—
|
|
|
$
|
24,876
|
|
Issuance of common stock
|
|
|
197,832
|
|
|
|
2
|
|
|
|
2,989
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2,991
|
|
Accrual of interest on loans to stockholders
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
(235
|
)
|
|
|
—
|
|
|
|
(235
|
)
|
Net income
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
12,058
|
|
|
|
—
|
|
|
|
—
|
|
|
|
12,058
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCES, December 31, 2005
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to these consolidated financial
statements.
F-5
Approach
Resources Inc. and Subsidiaries
Consolidated
Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2,709
|
|
|
$
|
21,202
|
|
|
$
|
12,058
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, depreciation and amortization
|
|
|
13,098
|
|
|
|
14,551
|
|
|
|
8,011
|
|
Amortization of loan origination fees
|
|
|
117
|
|
|
|
72
|
|
|
|
47
|
|
Non cash interest expense on convertible notes
|
|
|
2,095
|
|
|
|
—
|
|
|
|
—
|
|
Change in fair value of commodity derivatives
|
|
|
3,637
|
|
|
|
(8,668
|
)
|
|
|
4,163
|
|
Impairment of non-producing leasehold costs
|
|
|
267
|
|
|
|
558
|
|
|
|
—
|
|
Dry hole costs
|
|
|
883
|
|
|
|
1,614
|
|
|
|
1,187
|
|
Share-based compensation expense
|
|
|
4,646
|
|
|
|
34
|
|
|
|
—
|
|
Deferred income taxes
|
|
|
(296
|
)
|
|
|
11,102
|
|
|
|
6,448
|
|
Interest earned on loans to stockholders
|
|
|
—
|
|
|
|
—
|
|
|
|
(235
|
)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(2,657
|
)
|
|
|
7,389
|
|
|
|
(9,779
|
)
|
Prepaid expenses and other current assets
|
|
|
(349
|
)
|
|
|
221
|
|
|
|
(68
|
)
|
Accounts payable
|
|
|
(787
|
)
|
|
|
(14,284
|
)
|
|
|
12,129
|
|
Oil and gas payables
|
|
|
(3,146
|
)
|
|
|
(1,704
|
)
|
|
|
5,269
|
|
Accrued liabilities
|
|
|
10,529
|
|
|
|
2,218
|
|
|
|
1,358
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities
|
|
|
30,746
|
|
|
|
34,305
|
|
|
|
40,588
|
|
INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Advances under note receivable
|
|
|
—
|
|
|
|
—
|
|
|
|
(4,152
|
)
|
Payments received under note receivable
|
|
|
—
|
|
|
|
—
|
|
|
|
5,698
|
|
Additions to oil and gas properties
|
|
|
(51,845
|
)
|
|
|
(59,352
|
)
|
|
|
(73,730
|
)
|
Additions to other property and equipment, net
|
|
|
(178
|
)
|
|
|
(32
|
)
|
|
|
(40
|
)
|
Investments
|
|
|
(917
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash used in investing activities
|
|
|
(52,940
|
)
|
|
|
(59,384
|
)
|
|
|
(72,224
|
)
|
FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
Loan origination fees
|
|
|
(140
|
)
|
|
|
(69
|
)
|
|
|
(117
|
)
|
Borrowings under credit facility
|
|
|
64,285
|
|
|
|
119,547
|
|
|
|
103,775
|
|
Repayment of amounts outstanding under credit facility
|
|
|
(111,904
|
)
|
|
|
(101,353
|
)
|
|
|
(74,450
|
)
|
Proceeds from convertible notes
|
|
|
20,000
|
|
|
|
—
|
|
|
|
—
|
|
Borrowing from stockholder
|
|
|
—
|
|
|
|
3,500
|
|
|
|
—
|
|
Proceeds from issuance of common stock
|
|
|
72,377
|
|
|
|
6,498
|
|
|
|
2,991
|
|
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
|
|
|
22,062
|
|
|
|
26,771
|
|
|
|
32,199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CHANGE IN CASH AND CASH EQUIVALENTS
|
|
|
(132
|
)
|
|
|
1,692
|
|
|
|
563
|
|
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH
EQUIVALENTS
|
|
|
6
|
|
|
|
—
|
|
|
|
—
|
|
CASH AND CASH EQUIVALENTS, beginning of year
|
|
|
4,911
|
|
|
|
3,219
|
|
|
|
2,656
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of year
|
|
$
|
4,785
|
|
|
$
|
4,911
|
|
|
$
|
3,219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
4,117
|
|
|
$
|
3,269
|
|
|
$
|
600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for income taxes
|
|
$
|
1,287
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
|
|
|
|
|
|
|
|
|
|
|
|
|
Conversion of stockholder note into common stock
|
|
$
|
—
|
|
|
$
|
3,500
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of oil and gas properties
|
|
$
|
60,225
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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-6
Approach
Resources Inc. and Subsidiaries
|
|
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 onshore in the
United States and British Columbia. We focus our growth efforts
primarily on finding and developing natural gas reserves in
known tight sands and shale gas areas. We currently operate or
have oil and gas properties or interests in Texas, New Mexico,
Kentucky and British Columbia.
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 Company’s 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 AOG’s 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 Company’s 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, 2007 and 2006.
F-7
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):
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Mineral interests in properties
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
10,845
|
|
|
$
|
4,207
|
|
Proved properties
|
|
|
10,937
|
|
|
|
12,166
|
|
Wells and related equipment and facilities
|
|
|
234,067
|
|
|
|
137,753
|
|
Uncompleted wells, equipment and facilities
|
|
|
11,056
|
|
|
|
1,502
|
|
|
|
|
|
|
|
|
|
|
Total costs
|
|
|
266,905
|
|
|
|
155,628
|
|
Less accumulated depreciation, depletion and amortization
|
|
|
(36,622
|
)
|
|
|
(23,622
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
230,283
|
|
|
$
|
132,006
|
|
|
|
|
|
|
|
|
|
|
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, 2007 or
2006. 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, 2007, 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
$13.0 million, $14.5 million and $8.0 million for
the years ended December 31, 2007, 2006 and 2005,
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 $267,000
and $558,000 during the years ended December 31, 2007 and
2006, respectively related to our assessment of unproved
properties. 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 will
expire in April 2008. The impairment recorded during the year
ended December 31, 2006, 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. We noted no impairments of our unproved properties for the
year ended 2005.
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 No. 144, Accounting for the
Impairment or
F-8
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
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, 2007, 2006 or 2005.
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, 2007 or 2006.
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 pumpers’ salaries, saltwater
disposal, ad valorem taxes, 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, 2007 and 2006, we sold
substantially all of our oil and gas produced to five
purchasers. Additionally, substantially all of our accounts
receivable related to oil and gas sales were due from those five
purchasers at December 31, 2007 and 2006. 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.
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. As a
result of historically strong prices of oil and gas, the demand
for oilfield and drilling services has risen, and the costs of
these services may increase. We are particularly sensitive to
higher rig
F-9
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
costs and drilling rig availability, as we presently have
several rigs under contract, one of which is on a well-to-well
basis. 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 $88,000, $64,000 and $55,000 for the years
ended December 31, 2007, 2006 and 2005, respectively.
Note
Receivable
In conjunction with a farmout agreement, we entered into a full
recourse revolving promissory note for the benefit of a working
interest owner to fund its costs incurred drilling wells under
the farmout agreement. Effective December 31, 2005, we
purchased the working interest for $10.5 million by the
retirement of the note receivable and accrued interest of
approximately $3.5 million and the payment of approximately
$7.0 million in January 2006. The note provided for
interest at six percent per annum and was collateralized by the
working interest in the wells drilled under the farmout
agreement.
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 combined 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 “change
in fair value of 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
F-10
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
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.
Accrued
Liabilities
Following is a summary of our accrued liabilities at
December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Capital expenditures accrued
|
|
$
|
13,168
|
|
|
$
|
2,362
|
|
Operating expenses and other
|
|
|
1,380
|
|
|
|
559
|
|
Federal income taxes
|
|
|
216
|
|
|
|
1,314
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
14,764
|
|
|
$
|
4,235
|
|
|
|
|
|
|
|
|
|
|
Asset
Retirement Obligations
Our asset retirement obligations relate to future plugging and
abandonment expenses on oil and gas properties. The asset
retirement obligations were approximately $550,000 and $150,000
at December 31, 2007 and 2006, respectively. Based on the
expected timing of payments, the full asset retirement
obligation is classified as non-current.
Comprehensive
Income
For the years ended December 31, 2006 and 2005, there were
no elements of comprehensive income other than net income.
Following is a summary of our comprehensive income for the year
ended December 31, 2007:
|
|
|
|
|
Net income
|
|
$
|
2,709
|
|
Other comprehensive income:
|
|
|
|
|
Foreign currency translation adjustments
|
|
|
105
|
|
|
|
|
|
|
Comprehensive income
|
|
$
|
2,814
|
|
|
|
|
|
|
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 year ended December 31, 2007, we
recognized a $105,000 translation gain. Transaction gains and
losses for the years ended December 31, 2006 and 2005 were
insignificant.
F-11
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
Share-based
Compensation
Prior to January 1, 2006, we accounted for stock option
awards granted under our 2003 Stock Option Plan in accordance
with the recognition and measurement provisions of Accounting
Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees (“APB 25”) and related
Interpretations, as permitted by Statement of Financial
Accounting Standards No. 123, Accounting for Stock-Based
Compensation (“SFAS No. 123”).
Share-based employee compensation expense was not recognized in
the Company’s consolidated statements of operations prior
to January 1, 2006, as all stock option awards granted had
an exercise price equal to or greater than the estimated fair
market value of the common stock on the date of the grant. As
permitted by SFAS No. 123, we reported pro forma
disclosures presenting results and earnings (loss) per share as
if we had used the fair value recognition provisions of
SFAS No. 123 in the Notes to Consolidated Financial
Statements. Share-based compensation related to non-employees
and modifications of options granted were accounted for based on
the fair value of the related stock or options in accordance
with SFAS No. 123 and its interpretations.
Effective January 1, 2006, we adopted the provisions of
Statement of Financial Accounting Standards No. 123
(revised 2004), Share-Based Payment
(“SFAS No. 123(R)”), which requires the
measurement and recognition of compensation expense for all
share-based payment awards to employees and directors based on
estimated fair values. We adopted SFAS No. 123(R)
using the modified prospective transition method. In accordance
with the modified prospective application provisions of
SFAS No. 123(R), compensation cost for the portion of
awards that were outstanding as of January 1, 2006, for
which the requisite service was not rendered, are recognized as
the requisite service is rendered, based on the grant date fair
value estimated in accordance with the provisions of
SFAS No. 123(R). Additionally, compensation costs for
awards granted after January 1, 2006 are recognized over
the requisite service period based on the grant-date fair value.
In accordance with the modified prospective transition method,
our consolidated financial statements for prior periods have not
been restated to reflect the impact of SFAS No. 123(R).
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, 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(1)
|
|
|
|
|
|
|
60,548
|
|
|
|
|
|
Convertible notes(2)
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions
|
|
$
|
2,709
|
|
|
|
11,183,707
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-12
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005
|
|
|
|
Income
|
|
|
Shares
|
|
|
Per-Share
|
|
|
|
(Numerator)
|
|
|
(Denominator)
|
|
|
Amount
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
12,058
|
|
|
|
9,107,092
|
|
|
$
|
1.32
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options, treasury method(3)
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income plus assumed conversions
|
|
$
|
12,058
|
|
|
|
9,107,092
|
|
|
$
|
1.32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
We issued these shares in March 2007. Prior to that time, there
were no restricted shares outstanding. |
|
(2) |
|
The outstanding principal and interest under our convertible
debt was converted on November 7, 2007 into shares of
common stock (see Note 2 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. |
|
(3) |
|
Options to acquire 375,000 shares of our common stock were
anti-dilutive for the year ended December 31, 2005. |
The share amounts for the years ending 2006 and 2005 have been
restated to reflect the contribution agreement and the stock
split discussed in Note 2.
Recently
Issued Accounting Pronouncements
In March 2008, the Financial Accounting Standards Board
(“FASB”) issued Statement of Financial Accounting
Standard No. 161, Disclosures about Derivative Instruments
and Hedging Activities, an amendment of FASB Statement
No. 133 (“SFAS 161”). SFAS 161 amends
and expands the disclosure requirements of FASB Statement
No. 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 No. 133 and its related interpretations, and
(iii) how derivative instruments and related hedged items
affect and entity’s 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, the Financial Accounting Standards Board
(“FASB”) issued Statement of Financial Accounting
Standards No. 141 (revised 2007), Business Combinations
(“SFAS No. 141(R)”).
SFAS No. 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
F-13
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
to enable users of the financial statements to evaluate the
nature and financial effects of the business combination.
SFAS No. 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 No. 160, Noncontrolling Interests in
Consolidated Financial Statements, an Amendment of ARB
No. 51 (“SFAS No. 160”).
SFAS No. 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 parent’s 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
Company is currently evaluating the requirements of
SFAS No. 160 and has not yet determined the impact of
adoption, if any, on its financial position, results of
operations or cash flows.
In September 2006, Statement of Financial Accounting Standards
No. 157, Fair Value Measurements
(“SFAS 157”), was issued. SFAS 157 provides
guidance for using fair value to measure assets and liabilities.
It applies whenever other standards require or permit assets or
liabilities to be measured at fair value, but it does not expand
the use of fair value in any new circumstances. The provisions
of SFAS 157 are effective for financial statements issued
for fiscal years beginning after November 15, 2007. The
effect of adopting SFAS 157 has not been determined, it is
not expected to have a significant effect on our reported
financial position or earnings, but it will require additional
disclosure on our derivative instruments when adopted.
In February 2007, SFAS No. 159, The Fair Value Option
for Financial Assets and Financial Liabilities-Including an
Amendment of FASB Statement No. 115
(“SFAS 159”), was issued. SFAS 159 permits
an entity to choose to measure many financial instruments and
certain other items at fair value. The fair value option
established by SFAS 159 permits all entities to choose to
measure eligible items at fair value at specified election
dates. Unrealized gains and losses on items for which the fair
value option has been elected are to be recognized in earnings
at each subsequent reporting date. SFAS 159 is effective
for financial statements issued for fiscal years beginning after
November 15, 2007. The effect of adopting SFAS 159 has
not been determined, but it is not expected to have a
significant effect on reported financial position or earnings.
|
|
2.
|
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” or
“Selling Stockholder”). Upon the closing of the
transactions contemplated by 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 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
$60.2 million, representing 4,239,243 shares of
Approach Resources Inc. 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 is pending the
filing of Neo Canyon’s tax return. As a result, the
preliminary purchase price is expected to be finalized during
the
F-14
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
three months ended June 30, 2008. The following is a
summary of the preliminary purchase price and its allocation (in
thousands) based on our estimates described above assuming the
acquisition occurred on December 31, 2007:
|
|
|
|
|
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
|
|
|
9,089
|
|
Asset retirement obligations assumed
|
|
|
133
|
|
Post-closing purchase price adjustments
|
|
|
132
|
|
|
|
|
|
|
Total
|
|
$
|
60,225
|
|
|
|
|
|
|
Allocation:
|
|
|
|
|
Wells and equipment and related facilities
|
|
$
|
59,434
|
|
Mineral interests in oil and gas properties
|
|
|
791
|
|
|
|
|
|
|
Total
|
|
$
|
60,225
|
|
|
|
|
|
|
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-15
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 8, 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.
|
|
3.
|
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 5, 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-16
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
Line
of Credit
We have a revolving loan agreement with The Frost National Bank
and JPMorgan Chase Bank, NA (the “Agreement”), which
provides a borrowing base determined by the bank based on oil
and gas reserve values. The bank determines our borrowing base
semi-annually on or before each March 1 and September 1 based on
our oil and gas reserves. We or the bank can each request one
additional borrowing base redetermination each calendar year. In
February 2007, the line of credit was raised to
$100.0 million and the borrowing base was increased to
$75.0 million. In June 2007, the maturity date of the
Agreement was extended to July 2010. We had no borrowings
outstanding under the Agreement at December 31, 2007 while
borrowings outstanding at December 31, 2006 were
$47.6 million. As of March 26, 2008, we had
$13.8 million in long-term debt outstanding under the
Agreement. The borrowings bear interest based on the bank’s
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. The interest rate at
December 31, 2007 was 6.6%. Principal payments are not
required until the final maturity date of the agreement, at
which time any outstanding loan balances shall be due and
payable in full. In addition, the Agreement requires payment of
a quarterly fee equal to three eighths of one percent (0.375%)
of the unused portion of the borrowing base. The borrowings are
collateralized by substantially all of our oil and gas
properties. The Agreement contains various covenants, the most
restrictive of which requires us to maintain a modified current
ratio of at least one. The modified current ratio represents the
quotient of our current assets, less any unrealized gains on
commodity derivatives plus amounts available under the Agreement
divided by our current liabilities less unrealized losses on
commodity derivatives. We were in compliance with the covenants
at December 31, 2007.
We also have outstanding unused letters of credit under the
Agreement totaling $3.0 million at December 31, 2007,
which reduce amounts available for borrowing under the Agreement.
In January 2008 we entered into a new, $200.0 million
revolving loan agreement (“New Loan Agreement”) with
ARI as borrower, AOG, Approach Oil & Gas (Canada) Inc.
and Approach Resources I, LP as guarantors, and The Frost
National Bank and JPMorgan Chase Bank, NA, as lenders. The
borrowing base under the New Loan Agreement was initially set at
$75.0 million and will be redetermined semi-annually on or
before each April 1 and October 1 based on our oil and gas
reserves.
|
|
5.
|
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.
As discussed in Note 1, Significant Accounting
Policies — Shared-Based Compensation, effective
January 1, 2006, we adopted the fair value recognition
provisions of SFAS No. 123(R), using the modified
prospective transition method. Share-based compensation expense
resulting from the adoption of SFAS No. 123(R)
amounted to $4.6 million and $34,000 for the years ended
December 31, 2007 and 2006, respectively. Such amounts
represent the estimated fair value of options for which the
requisite service period elapsed during 2007 and 2006. There was
no tax benefit recognized in relation to this change.
F-17
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
Had we followed the fair value recognition provisions of
SFAS 123 for the year ended December 31, 2005, our
operating results and earnings per share would have been
affected as follows, (in thousands, except per share amounts):
|
|
|
|
|
|
|
2005
|
|
|
Net income as reported
|
|
$
|
12,058
|
|
Basic and diluted earnings per share as reported
|
|
$
|
1.32
|
|
Share-based employee compensation costs, net of related tax
effects, included in net income as reported
|
|
|
—
|
|
Share-based employee compensation costs, net of related tax
effects, that would have been included in net income if the
fair-value-based method had been applied to all awards
|
|
|
(34
|
)
|
|
|
|
|
|
Pro forma net income as if the fair-value-based method had been
applied to all awards
|
|
$
|
12,024
|
|
|
|
|
|
|
Pro forma basic and diluted earnings per share as if the
fair-value-based method had been applied to all awards
|
|
$
|
1.32
|
|
|
|
|
|
|
The fair value of each option granted was estimated using an
option-pricing model with the following weighted average
assumptions during the year ended December 31, 2007. There
were no grants during the years ended December 31, 2006 and
2005.
|
|
|
|
|
Expected dividends
|
|
|
—
|
|
Expected volatility
|
|
|
68%
|
|
Risk-free interest rate
|
|
|
3.9%
|
|
Expected life
|
|
|
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.
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 No. 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-18
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, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable (fully vested) at December 31, 2007
|
|
|
274,041
|
|
|
$
|
3.33
|
|
|
|
6.63
|
|
|
$
|
2,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 2.
The fair market value of the stock options granted during the
year ended December 31, 2007 was $7.69 per share. Total
unrecognized share-based compensation expense from unvested
stock options as of December 31, 2007 was
$1.5 million, and will be recognized over a remaining
service period of 2.86 years. The intrinsic value of the
options exercised during the year ended December 31, 2007
was $634,000.
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 411,041 shares with an approximate
aggregate market value of $5.2 million at the time of grant
were granted during the year ended December 31, 2007. A
summary of the status of non-vested shares for the year ended
December 31, 2007, is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
Grant-Date
|
|
|
Shares
|
|
|
Fair Value
|
|
Nonvested at the beginning of the year
|
|
|
—
|
|
|
$
|
—
|
Granted
|
|
|
411,041
|
|
|
|
12.70
|
Vested
|
|
|
(368,541
|
)
|
|
|
12.26
|
|
|
|
|
|
|
|
|
Nonvested at the end of the year
|
|
|
42,500
|
|
|
$
|
16.50
|
|
|
|
|
|
|
|
|
The unrecognized compensation of $657,000 related to the
nonvested shares will be recognized over a remaining service
period of 1.86 years.
F-19
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
Our (benefit) provision for income taxes comprised the following
during the years ended December 31, 2007, 2006 and 2005 (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
188
|
|
|
$
|
550
|
|
|
$
|
509
|
|
State
|
|
|
—
|
|
|
|
105
|
|
|
|
71
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
188
|
|
|
|
655
|
|
|
|
580
|
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(296
|
)
|
|
|
11,243
|
|
|
|
5,663
|
|
State
|
|
|
—
|
|
|
|
(141
|
)
|
|
|
785
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
(296
|
)
|
|
|
11,102
|
|
|
|
6,448
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Benefit) provision for income taxes
|
|
$
|
(108
|
)
|
|
$
|
11,757
|
|
|
$
|
7,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income (benefit) tax expense differed from the amounts
computed by applying the U.S. Federal statutory tax rates
to pre-tax income for the years ended December 31, 2007,
2006 and 2005 as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Statutory tax (benefit) at 34%
|
|
$
|
884
|
|
|
$
|
11,205
|
|
|
$
|
6,490
|
|
State taxes (benefit), net of federal impact
|
|
|
29
|
|
|
|
990
|
|
|
|
569
|
|
Changes in enacted rates
|
|
|
—
|
|
|
|
(1,077
|
)
|
|
|
—
|
|
Permanent differences(1)
|
|
|
609
|
|
|
|
—
|
|
|
|
—
|
|
Other differences
|
|
|
(35
|
)
|
|
|
(173
|
)
|
|
|
(250
|
)
|
Change in valuation allowance
|
|
|
(1,595
|
)
|
|
|
812
|
|
|
|
219
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(108
|
)
|
|
$
|
11,757
|
|
|
$
|
7,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Amount primarily relates to the beneficial conversion feature on
the convertible notes, see Note 2. |
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 No. 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.
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
F-20
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
a long-term liability of $26.3 million and
$17.5 million at December 31, 2007 and 2006,
respectively. Significant components of net deferred tax assets
and liabilities are (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Difference in depreciation and capitalization
methods — furniture, fixtures and equipment
|
|
$
|
—
|
|
|
$
|
28
|
|
Net operating loss carryforwards
|
|
|
2,846
|
|
|
|
1,805
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
2,846
|
|
|
|
1,833
|
|
Less: valuation allowance
|
|
|
—
|
|
|
|
(1,595
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
2,846
|
|
|
|
238
|
|
Deferred tax liability:
|
|
|
|
|
|
|
|
|
Difference in depreciation, depletion and capitalization
methods — oil and gas properties
|
|
|
(28,877
|
)
|
|
|
(16,226
|
)
|
Unrealized gain on commodity derivatives
|
|
|
(301
|
)
|
|
|
(1,561
|
)
|
Other
|
|
|
(10
|
)
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(29,188
|
)
|
|
|
(17,787
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax (liability)
|
|
$
|
(26,342
|
)
|
|
$
|
(17,549
|
)
|
|
|
|
|
|
|
|
|
|
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
management’s 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
|
|
|
3,011
|
|
|
|
|
|
|
Total
|
|
$
|
8,210
|
|
|
|
|
|
|
F-21
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
We periodically enter into put options, call options,
combinations of put and call options (referred to as a costless
collar), and swaps to mitigate the risk of fluctuations in
commodity prices related to our natural gas production. As
discussed in Note 1, Summary of Significant Accounting
Policies, we do not designate our derivative instruments as cash
flow hedges. At December 31, 2007, we had the following
commodity derivative positions outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
$/MMBtu
|
|
Period
|
|
Monthly
|
|
|
Total
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Fixed
|
|
|
NYMEX — Henry Hub
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costless collar 2008
|
|
|
186,000
|
|
|
|
2,230,000
|
|
|
$
|
7.50
|
|
|
$
|
11.45
|
|
|
|
|
|
Costless collar 2009
|
|
|
180,000
|
|
|
|
2,160,000
|
|
|
$
|
7.50
|
|
|
$
|
10.50
|
|
|
|
|
|
WAHA differential
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps 2008
|
|
|
186,000
|
|
|
|
2,230,000
|
|
|
|
|
|
|
|
|
|
|
|
(0.69
|
)
|
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 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 contracts and then obtained mark-to-market valuations for
our collar positions from our counterparty and reviewed such
valuations for reasonableness based on forward prices in
relation to our contractual ceiling and floor prices. Realized
gains as losses are also included in other income (expense) on
our consolidated statements of operations.
We are exposed to credit loss in the event of nonperformance by
the counterparty on our oil and gas swaps. However, we do not
anticipate nonperformance by the counterparty over the term of
the swaps.
Subsequent to December 31, 2007, we entered into the
following commodity derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume (MMBtu)
|
|
|
$/MMBtu
|
|
Period
|
|
Monthly
|
|
|
Total
|
|
|
Floor
|
|
|
Ceiling
|
|
|
Fixed
|
|
|
NYMEX — Henry Hub
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costless collars 2008
(3rd
quarter)
|
|
|
100,000
|
|
|
|
300,000
|
|
|
$
|
7.00
|
|
|
$
|
9.10
|
|
|
|
|
|
Costless collars 2008
(2nd —
4th quarter)
|
|
|
200,000
|
|
|
|
1,800,000
|
|
|
$
|
9.00
|
|
|
$
|
12.20
|
|
|
|
|
|
Costless collars 2009
|
|
|
130,000
|
|
|
|
1,560,000
|
|
|
$
|
8.50
|
|
|
$
|
11.70
|
|
|
|
|
|
WAHA differential
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed price swaps 2008
(2nd —
4th quarter)
|
|
|
100,000
|
|
|
|
900,000
|
|
|
|
|
|
|
|
|
|
|
$
|
(0.67
|
)
|
Fixed price swaps
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2nd
quarter 2008
|
|
|
100,000
|
|
|
|
300,000
|
|
|
|
|
|
|
|
|
|
|
$
|
8.10
|
|
4th quarter
2008
|
|
|
100,000
|
|
|
|
300,000
|
|
|
|
|
|
|
|
|
|
|
$
|
8.63
|
|
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
F-22
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
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
(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.
|
|
9.
|
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.
|
|
10.
|
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 $1.3 million at
December 31, 2007.
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 in 2009 and 2011. The following
is a schedule by years of future minimum rental payments
required under our operating lease arrangements, net of sublease
collections expected to be received as of December 31, 2007
(in thousands):
|
|
|
|
|
2008
|
|
$
|
374
|
|
2009
|
|
|
310
|
|
2010
|
|
|
262
|
|
2011
|
|
|
269
|
|
2012
|
|
|
227
|
|
Collections
|
|
|
(165
|
)
|
|
|
|
|
|
Total
|
|
$
|
1,277
|
|
|
|
|
|
|
F-23
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
Rent expense under our lease arrangements amounted to $198,000,
$137,000 and $130,000 for the years ended December 31,
2007, 2006 and 2005, 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.
|
|
11.
|
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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved properties
|
|
$
|
5,480
|
|
|
$
|
4,071
|
|
|
$
|
369
|
|
Proved properties
|
|
|
59,594
|
|
|
|
356
|
|
|
|
11,592
|
|
Exploration costs
|
|
|
9,897
|
|
|
|
3,769
|
|
|
|
1,347
|
|
Development costs
|
|
|
37,451
|
|
|
|
51,820
|
|
|
|
59,972
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred
|
|
$
|
112,422
|
|
|
$
|
60,016
|
|
|
$
|
73,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Set forth below is certain information regarding the results of
operations for oil and gas producing activities (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Revenues
|
|
$
|
39,114
|
|
|
$
|
46,672
|
|
|
$
|
43,264
|
|
Production costs
|
|
|
(5,474
|
)
|
|
|
(5,625
|
)
|
|
|
(4,885
|
)
|
Exploration expenses
|
|
|
(883
|
)
|
|
|
(1,640
|
)
|
|
|
(733
|
)
|
Impairment
|
|
|
(267
|
)
|
|
|
(558
|
)
|
|
|
—
|
|
Depletion
|
|
|
(13,010
|
)
|
|
|
(14,487
|
)
|
|
|
(7,956
|
)
|
Income tax expenses
|
|
|
(6,623
|
)
|
|
|
(9,114
|
)
|
|
|
(11,101
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations
|
|
$
|
12,857
|
|
|
$
|
15,248
|
|
|
$
|
18,589
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-24
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
|
|
12.
|
Disclosures
About Oil and Gas Producing Activities (unaudited)
|
The estimates of proved reserves and related valuations for the
years ended December 31, 2007, 2006 and 2005 were based
upon the reports prepared by DeGolyer and MacNaughton,
independent petroleum engineers (for 2007 and 2006) and by
Cawley, Gillespie & Associates, Inc., independent
petroleum engineers (for 2005). Each year’s estimate of
proved reserves and related valuations was prepared in
accordance with the provisions of Statement of Financial
Accounting Standards No. 69
(“SFAS No. 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 Approach’s changes in
quantities of proved oil and natural gas reserves for the years
ended December 31, 2005, 2006 and 2007, are as follows:
|
|
|
|
|
|
|
|
|
|
|
Natural Gas
|
|
|
Oil & NGLs
|
|
|
|
(MMcf)
|
|
|
(MBbl)
|
|
|
Balance — January 1, 2005
|
|
|
57,697
|
|
|
|
353
|
|
Extensions and discoveries
|
|
|
2,755
|
|
|
|
26
|
|
Purchases of minerals in place
|
|
|
6,400
|
|
|
|
68
|
|
Production
|
|
|
(4,666
|
)
|
|
|
(58
|
)
|
Revisions to previous estimates
|
|
|
40,219
|
|
|
|
697
|
|
|
|
|
|
|
|
|
|
|
Balance — December 31, 2005
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves:
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
47,078
|
|
|
|
454
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006
|
|
|
51,004
|
|
|
|
496
|
|
|
|
|
|
|
|
|
|
|
December 31, 2007
|
|
|
70,251
|
|
|
|
1,268
|
|
|
|
|
|
|
|
|
|
|
The following is a discussion of the material changes in our
proved reserve quantities for the years ended December 31,
2007, 2006 and 2005:
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.
F-25
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
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.
Year
Ended December 31, 2005
Our drilling program in Ozona Northeast resulted in
classification of reserves as proved, which accounts for the
additional quantities listed under extensions and discoveries.
Additionally we purchased the working interests of one of the
non-operating participants in Ozona Northeast during 2005, which
accounts for the additional quantities listed under purchases of
minerals in place. The approval of the
20-acre down
spacing in December 2005 and the increase in average gas price
attributable to our proved reserves from $6.93 per Mcf at
December 31, 2004 to $9.20 per Mcf at December 31,
2005, were the primary reason for the additional 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 No. 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 Approach’s 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Future cash flows
|
|
$
|
1,567,251
|
|
|
$
|
709,184
|
|
|
$
|
1,003,363
|
|
Future production costs
|
|
|
(401,579
|
)
|
|
|
(198,023
|
)
|
|
|
(193,171
|
)
|
Future development costs
|
|
|
(191,738
|
)
|
|
|
(108,451
|
)
|
|
|
(101,152
|
)
|
Future income tax expense
|
|
|
(285,384
|
)
|
|
|
(109,784
|
)
|
|
|
(238,013
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows
|
|
|
688,550
|
|
|
|
292,926
|
|
|
|
471,027
|
|
10% annual discount for estimated timing of cash flows
|
|
|
(472,590
|
)
|
|
|
(215,049
|
)
|
|
|
(324,588
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
215,960
|
|
|
$
|
77,877
|
|
|
$
|
146,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007, 2006, and 2005 was
immaterial.
F-26
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Balance, beginning of period
|
|
$
|
77,877
|
|
|
$
|
146,439
|
|
|
$
|
60,278
|
|
Net change in sales and transfer prices and in production
(lifting) costs related to future production
|
|
|
57,231
|
|
|
|
(106,246
|
)
|
|
|
53,167
|
|
Changes in estimated future development costs
|
|
|
(39,506
|
)
|
|
|
(43,229
|
)
|
|
|
(87,109
|
)
|
Sales and transfers of oil and gas produced during the period
|
|
|
(33,640
|
)
|
|
|
(41,047
|
)
|
|
|
(38,379
|
)
|
Net change due to extensions, discoveries and improved recovery
|
|
|
107,864
|
|
|
|
28,418
|
|
|
|
7,613
|
|
Net change due to purchase of minerals in place
|
|
|
97,328
|
|
|
|
—
|
|
|
|
17,804
|
|
Net change due to revisions in quantity estimates
|
|
|
(21,001
|
)
|
|
|
(22,112
|
)
|
|
|
116,125
|
|
Previously estimated development costs incurred during the period
|
|
|
28,026
|
|
|
|
52,108
|
|
|
|
53,116
|
|
Accretion of discount
|
|
|
12,843
|
|
|
|
15,546
|
|
|
|
16,686
|
|
Other
|
|
|
8,077
|
|
|
|
(4,303
|
)
|
|
|
9,616
|
|
Net change in income taxes
|
|
|
(79,139
|
)
|
|
|
52,303
|
|
|
|
(62,478
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
215,960
|
|
|
$
|
77,877
|
|
|
$
|
146,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average wellhead prices in effect at December 31, 2007,
2006 and 2005 inclusive of adjustments for quality and location
used in determining future net revenues related to the
standardized measure calculation are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Oil (per Bbl)
|
|
$
|
93.30
|
|
|
$
|
58.05
|
|
|
$
|
56.50
|
|
Natural gas liquids (per Bbl)
|
|
$
|
60.09
|
|
|
$
|
30.55
|
|
|
$
|
—
|
|
Gas (per Mcf)
|
|
$
|
8.10
|
|
|
$
|
6.55
|
|
|
$
|
9.20
|
|
Selected Quarterly Financial Data (unaudited), (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
(2,157
|
)
|
|
|
(1,108
|
)
|
|
|
(998
|
)
|
|
|
(956
|
)
|
Realized gain on commodity derivates
|
|
|
1,409
|
|
|
|
1,080
|
|
|
|
88
|
|
|
|
2,155
|
|
Change in fair value of 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
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-27
Approach
Resources Inc. and Subsidiaries
Notes to
Consolidated Financial
Statements — (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
(1,047
|
)
|
|
|
(1,058
|
)
|
|
|
(984
|
)
|
|
|
(725
|
)
|
Realized gain on commodity derivatives
|
|
|
2,012
|
|
|
|
1,126
|
|
|
|
1,660
|
|
|
|
1,424
|
|
Change in fair value of 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-28
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 Company’s 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 Company’s 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 Company’s 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 Company’s Registration Statement on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.2
|
|
Contribution Agreement by and among Approach Resources Inc. and
the equity holders identified therein, dated June 29, 2007
(filed as Exhibit 10.2 to the Company’s Registration
Statement on
Form S-1
filed July 12, 2007 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 Company’s Registration Statement
on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.4†
|
|
Employment Agreement by and between Approach Resources Inc. and
Steven P. Smart dated January 1, 2003 (filed as
Exhibit 10.4 to the Company’s Registration Statement
on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.5†
|
|
Employment Agreement by and between Approach Resources Inc. and
Glenn W. Reed dated January 1, 2003 (filed as
Exhibit 10.5 to the Company’s Registration Statement
on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.6†
|
|
Approach Resources Inc. 2007 Stock Incentive Plan, effective as
of June 28, 2007 (filed as Exhibit 10.6 to the
Company’s Registration Statement on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.7
|
|
Convertible Promissory Note issued by Approach Oil &
Gas Inc. to Yorktown Energy Partners VII, L.P. dated
June 25, 2007 (filed as Exhibit 10.7 to the
Company’s Registration Statement on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.8
|
|
Convertible Promissory Note issued by Approach Oil &
Gas Inc. to Lubar Equity Fund, LLC dated June 25, 2007
(filed as Exhibit 10.8 to the Company’s Registration
Statement on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.9
|
|
$100,000,000 Revolving Amended and Restated Credit Agreement by
and among Approach Resources I, LP, as borrower, The Frost
National Bank, as administrative agent and lender, and the
lenders party thereto, dated February 15, 2007 (filed as
Exhibit 10.9 to the Company’s Registration Statement
on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
|
10
|
.10
|
|
Amendment to Amended and Restated Credit Agreement dated as of
February 15, 2007 between Approach Resources I, LP,
The Frost National Bank, as administrative agent and lender, and
the lenders party thereto, dated June 15, 2007 (filed as
Exhibit 10.10 to the Company’s Registration Statement
on
Form S-1
filed July 12, 2007 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 Company’s 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 Company’s 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 Company’s Registration
Statement on
Form S-1
filed July 12, 2007 and incorporated herein by reference).
|
54
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
10
|
.14†
|
|
Form of Summary of Stock Option Grant under Approach Resources
Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.14 to
the Company’s Registration Statement on
Form S-1/A
filed October 18, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.15†
|
|
Form of Stock Award Agreement under Approach Resources Inc. 2007
Stock Incentive Plan (filed as Exhibit 10.15 to the
Company’s Registration Statement on
Form S-1/A
filed October 18, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.16
|
|
Second Amendment to Amended and Restated Credit Agreement dated
as of February 15, 2007 between Approach Resources I,
LP, The Frost National Bank, as administrative agent, and the
lenders party thereto, dated July 20, 2007 (filed as
Exhibit 10.16 to the Company’s Registration Statement
on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.17
|
|
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
Company’s Current Report on
Form 8-K/A
filed December 3, 2007 and incorporated herein by
reference).
|
|
10
|
.18
|
|
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 Company’s
Registration Statement on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.19
|
|
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
Company’s Registration Statement on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.20
|
|
Third Amendment to Amended and Restated Credit Agreement dated
as of February 15, 2007 between Approach Resources I,
LP, The Frost National Bank, as administrative agent, and the
lenders party thereto, dated September 1, 2007 (filed as
Exhibit 10.20 to the Company’s Registration Statement
on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.21
|
|
Partial Assignment of Oil and Gas Leases and Related Property
dated effective August 1, 2006 among Neo Canyon
Exploration, L.P. and the other assignors identified therein,
and Approach Resources I, L.P., as assignee (filed as
Exhibit 10.21 to the Company’s Registration Statement
on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.22
|
|
Carry and Earning Agreement dated July 13, 2007 by and
between EnCana Oil & Gas (USA) (filed as
Exhibit 10.22 to the Company’s Registration Statement
on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.23
|
|
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 Company’s Registration Statement
on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.24
|
|
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 Company’s Registration Statement on
Form S-1/A
filed September 13, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.25
|
|
Gas Purchase Contract dated June 1, 2006 by and between
Approach Operating, L.P. and Belvan Partners, L.P. (filed as
Exhibit 10.25 to the Company’s Registration Statement
on
Form S-1/A
filed October 18, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.26
|
|
Lease Crude Oil Purchase Agreement dated May 1, 2004 by and
between ConocoPhillips and Approach Operating LLC (filed as
Exhibit 10.26 to the Company’s Registration Statement
on
Form S-1/A
filed October 18, 2007 (File
No. 333-144512)
and incorporated herein by reference).
|
|
10
|
.27
|
|
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 Company’s Current Report
on
Form 8-K
filed November 28, 2007 and incorporated herein by
reference).
|
55
|
|
|
|
|
Exhibit
|
|
|
Number
|
|
Description of Exhibit
|
|
|
10
|
.28
|
|
$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 Company’s Current Report on
Form 8-K
filed January 18, 2008 and incorporated herein by
reference).
|
|
10
|
.29
|
|
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 Company’s Current Report on
Form 8-K
filed February 22, 2008 and incorporated herein by
reference).
|
|
*14
|
.1
|
|
Code of Conduct.
|
|
*23
|
.1
|
|
Consent of Hein & Associates LLP.
|
|
*23
|
.2
|
|
Consent of DeGolyer and MacNaughton.
|
|
*23
|
.3
|
|
Consent of Cawley, Gillespie & Associates, Inc.
|
|
*31
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
*31
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
*32
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
*32
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
* |
|
Filed herewith. |
|
† |
|
Denotes management contract or compensatory plan or arrangement. |
56