UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-34224
Brigham Exploration Company
(Exact name of Registrant as Specified in its Charter)
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Delaware
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75-2692967 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
6300 Bridge Point Parkway, Building 2, Suite 500, Austin, Texas 78730
(Address of principal executive offices) (Zip Code)
(512) 427-3300
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of Each Class
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Name of Each Exchange on Which Registered |
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Common Stock, $0.01 par value
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NASDAQ Global Select Market |
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes þ No o
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 whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of Registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K.
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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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Accelerated filer þ
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b of
the Act). Yes o No þ
As of June 30, 2009, the registrant had 82,764,420 shares of voting common stock outstanding.
The aggregate market value of the registrants outstanding shares of voting common stock held by
non-affiliates, based on the closing price of these shares on June 30, 2009 of $3.50 per share as
reported on The NASDAQ Global Select Market, was $277 million. Shares held by each executive
officer and director and by each person who owns 10% or more of the outstanding common stock are
considered affiliates. The determination of affiliate status is not necessarily a conclusive
determination for other purposes.
As
of February 24, 2010, the registrant had
100,125,808 shares of voting common stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrants 2010 Annual Meeting of Stockholders
to be held on May 26, 2010, are incorporated by reference in Part III of this Form 10-K. Such
definitive proxy statement will be filed with the Securities and Exchange Commission not later than
120 days subsequent to December 31, 2009.
BRIGHAM EXPLORATION COMPANY
TABLE OF CONTENTS
BRIGHAM EXPLORATION COMPANY
2009 ANNUAL REPORT ON FORM 10-K
PART I
Overview
We are an independent exploration, development and production company that utilizes advanced
exploration, drilling and completion technologies to systematically explore for, develop and
produce domestic onshore oil and natural gas reserves. We focus our activities in provinces where
we believe these technologies, including horizontal drilling, multi-stage isolated fracture
stimulations and 3-D seismic imaging, can be used to effectively maximize our return on invested
capital.
Historically, our exploration and development activities have been focused in the Onshore Gulf
Coast, the Anadarko Basin and West Texas. We also regularly evaluate opportunities to expand our
activities to areas that may offer attractive exploration and development potential. In response
to this strategy, in late 2005 we began acquiring acreage within the Williston Basin in North
Dakota and Montana and as of December 31, 2009, we have approximately 453,147 gross and 282,584 net
leasehold acres in the Williston Basin. In late 2007, the majority of our drilling capital expenditures
shifted from our historically active areas in the Onshore Gulf Coast, the Anadarko Basin and West
Texas to the Williston Basin, where we are currently targeting the Bakken, Three Forks and Red
River objectives. Through year-end 2009, we have invested in excess of $222 million on drilling,
land and seismic in this region.
At December 31, 2009, our estimated proved reserves of 27.7 MMBoe had a standardized measure
of $246.5 million and a pre-tax PV10% value of $254.1 million. Approximately 60% of our proved
reserves are oil and we operate approximately 74% of our proved reserves. Our average daily
production volumes for 2009 were 5,034 Boe, which represents a 5% decrease from those in 2008.
The following table provides information regarding our assets and operations located in our
core areas.
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At December 31, 2009 |
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2009 |
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Productive |
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3-D |
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Average |
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Proved |
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Pre-Tax |
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% |
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Wells |
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Seismic |
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Daily Production |
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Province |
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Reserves(a) |
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PV10%(b)(c) |
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Oil |
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Gross |
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Net |
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Data |
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Volumes (d) |
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(MMBoe) |
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(Millions) |
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(Sq. Miles) |
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(Boe) |
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Rocky Mountains |
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15.4 |
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133.6 |
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89 |
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115 |
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22.9 |
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1,402 |
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1,816 |
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Onshore Gulf Coast |
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8.2 |
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87.7 |
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21 |
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76 |
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38.3 |
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4,459 |
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2,194 |
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Anadarko Basin |
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2.9 |
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13.1 |
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82 |
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21.3 |
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2,381 |
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726 |
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West Texas and Other |
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1.2 |
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19.7 |
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83 |
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24.6 |
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4,698 |
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298 |
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Total |
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27.7 |
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$ |
254.1 |
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60 |
% |
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356 |
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107.1 |
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12,940 |
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5,034 |
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(a) |
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MMBoe is defined as one million barrels of oil equivalent determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
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The prices used to calculate this measure were $61.18 per barrel of oil and $3.87 per MMbtu
of natural gas. The prices represent the average prices per barrel of oil and per MMbtu of
natural gas at the beginning of each month in the 12-month period prior to the end of the
reporting period. These prices were adjusted to reflect applicable
transportation and quality differentials on a well-by-well basis to
arrive at realized sales prices used to estimate our reserves at this
date. |
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The standardized measure for our proved reserves at December 31, 2009 was $246.5 million.
See Item 2. Properties Reconciliation of Standardized Measure to Pre-tax PV10% for a
definition of pre-tax PV10% and a reconciliation of our standardized measure to our pre-tax
PV10% value. |
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Average daily production volumes calculated based on 360 day year. Includes approximately
16,475 barrels of oil produced in the Williston Basin during 2009 and recorded as inventory at
year-end 2009. Ending inventory at year end 2008 and 2007 was not material. Adjusting the
production volumes for amounts included in
inventory would result in average daily sales volumes in the Rocky Mountains and in total of 1,770 and 4,988 barrels of oil equivalent, respectively. |
2
As a result of our exploration and development activities, since inception we have drilled,
completed, or are completing 885 gross wells, consisting of 524 exploration and 361 development
wells with an average completion rate of 76%. Over the three year period ended December 31, 2009,
we drilled, completed, or were completing 154 gross wells, consisting of 19 exploratory and 135
development wells with an average completion rate of 93%. Our improved completion rate over the
past three years compared to that since inception is attributable to our increased
level of activity in the Williston Basin, which is an unconventional
resource basin generally providing
more predictable drilling results. During 2009, we drilled, completed or were
completing 57 gross wells, consisting of two exploratory wells and 55 development wells with an
average completion rate of 98%. Our higher level of development drilling and higher completion
rate in 2009 as compared to 2007 and 2008 is also attributable to our increased level of activity
in the Williston Basin.
Since inception, we have retained an average working interest of approximately 34% in our wells. Over the
last three years, we have retained an average working interest of approximately 25% in our wells. In 2009, we
retained an average working interest of approximately 15% in our wells. The decrease in our working interest
retained during 2009 was attributable to the reduction in our operated drilling activity during the
first half of 2009 (outlined below) and the increased level of non-operated activity in the
Williston Basin, where we participated in a number of lower working interest wells in Mountrail
County, North Dakota.
Over the three year period ended December 31, 2009, we have spent approximately $291.2 million on drilling
capital expenditures and approximately $55.1 million on land and seismic. In 2009, we spent a total of approximately $58.2
million on drilling capital expenditures and approximately $1.8 million on land and seismic. Our 2009 spending
on drilling, land and seismic represents a 65% decrease from that in 2008, as we curtailed our operated
drilling and completion activity in the first half of 2009. The decline in operated activity was triggered by the financial crisis and
recession, which depressed commodity prices, and high drilling and completion costs, the reduction
of which typically lags commodity price decreases as operators must phase in drilling activity
reductions. For 2010, we anticipate spending approximately $183.7 million on drilling capital expenditures and
approximately $15.6 million on land and seismic. The increase in our 2010 capital expenditure budget as compared
to that for 2009 is a result of the improvement in crude oil prices and the reduction in drilling and
completion costs, both of which have led to improved rates of return for our Williston Basin
drilling program. Our increased level of activity is also attributable to our improved liquidity
position, as a result of our May and October 2009 equity offerings, and our improved Williston
Basin drilling results, which reflect our recent innovation in how we drill and complete
horizontal wells. Our activity in 2010 will largely be focused in the Williston Basin where we are
targeting the Bakken and Three Forks formations, which are primarily unconventional oil resource
plays.
Business Strategy
Our business strategy is to create value for our stockholders by growing reserves, production
volumes and cash flow utilizing advanced exploration, drilling and completion technologies to
systematically explore for, develop and produce domestic onshore oil and natural gas reserves. Key
elements of our business strategy include:
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Focus on Provinces. We plan to concentrate the majority of our near term capital
expenditures in the Williston Basin, where we believe our approximately 282,584 net acres and the
application of advanced drilling and completion techniques provide us with a significant
competitive advantage in developing both the Bakken and Three Forks formations. In
addition to the Williston Basin, we have a multi-year inventory of drilling prospects in
the following three provinces: Onshore Gulf Coast, Anadarko Basin and West Texas. Our
projects in these provinces provide us with important future drilling investment
diversification. |
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Leverage our Engineering and Operational Expertise. Our staff is proficient with
state-of-the-art drilling and completion technologies, including directional drilling,
horizontal drilling and multi-stage isolated fracture stimulations. Our drilling and
completion techniques in the Williston Basin have rapidly evolved from drilling and
completing long lateral wells with single large uncontrolled fracture stimulations in late
2006 to drilling long lateral wells with 20 isolated fracture stimulation stages in the
fourth quarter 2008 and first quarter 2009. Most recently, we have completed long lateral
wells with up to 32 isolated fracture
stimulation stages. We will continue to refine our drilling and completion techniques in
order to attempt to enhance well performance and the associated estimated ultimate
recoveries and rates of return. |
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Capitalize on Internally Generated Exploration Successes Through Disciplined Development Activities. From
1990 to 1999, we grew our reserves and production volumes primarily through successful
exploration drilling. In recent years, our exploratory drilling success has generated a
multi-year inventory of development drilling locations. We have a 19 year track record of
successfully generating and drilling exploration wells in new oil and natural gas plays.
We are particularly interested in those plays with attractive exploration and development
potential that complement our current exploration, development and production activities.
After identifying such a play, we will often selectively build an acreage position in the
play. Our current inventory of drilling locations in the Williston Basin, Vicksburg and
Hunton plays are examples of successful projects where our position in the play was
internally identified and originated. |
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Enhance Returns Through Operational Control. We typically leverage our technical and
operational expertise by seeking to maintain operational control of our exploration and
drilling activities. As operator, we retain more control over the timing, selection and
process of drilling prospects, which enhances our ability to maximize our return on
invested capital. Since we generate most of our own projects, we generally have the
ability to retain operational control over all phases of our exploration and development
activities. |
Exploration and Development Staff
Our experienced exploration staff includes 11 geologists, six geophysicists, two computer
applications specialists and five geological technicians. Our geologists and geophysicists have
varied, but complementary backgrounds. Their diversity of experience in a wide-range of geological
and geophysical settings, combined with various technical specializations (from hardware and
systems to software and seismic data processing), provides us with valuable technical, intellectual
resources. Our geologists and geophysicists have an average of more than 19 years of experience in
the industry. We have assembled our team of geologists and geophysicists with backgrounds that
complement the areas where we focus our exploration and development activities. By integrating
both geologic and geophysical expertise within our project teams, we believe we possess a
competitive advantage in our exploration approach.
Our land department staff includes four landmen with an average of more than 22 years of
experience, primarily within our core provinces, and four lease and division order analysts. Our
land department contributed to pioneering many of the innovations that have facilitated exploration
using large 3-D seismic projects.
Operations and Operations Staff
In an effort to retain better control of our project timing, drilling, operational costs and
production volumes, we attempt to operate as many of the wells we drill as possible. We operated
26% of the gross wells and 83% of the net wells that we drilled during 2009, as compared with 10%
of the gross wells and 17% of the net wells we drilled during 1996. In 2010, we anticipate we will
operate an increased number of wells as we currently have four operated rigs running in the
Williston Basin and, subject to commodity price risk, service costs and other factors, anticipate
retaining those rigs throughout the year. As a result of our increased operational control, wells
operated by us constituted 74% of our proved reserves at year-end 2009, as compared to only 5% at
year-end 1996.
Our operations staff includes seven engineers who have an average of 15 years of experience in
drilling, reservoir, operations or environmental engineering primarily within our four core
operating provinces. These engineers work closely with our geologists and geophysicists and are
integrally involved in all phases of the exploration and development process, including preparation
of pre- and post-drill reserve estimates, well design, production management and analysis of full
cycle risked drilling economics. We conduct field operations for our
operated oil and natural gas properties through a combination of our field and third party
contract personnel. We recently opened a field office in Mountrail County, North Dakota in order
to more effectively oversee our Williston Basin activities, which we expect to account for the
majority of our capital expenditure budget for 2010.
4
Oil and Natural Gas Market and Major Customers
In an effort to improve price realizations from the sale of our oil and natural gas, we manage
our commodities marketing activities in-house, which enables us to market and sell our oil and
natural gas to a broader universe of potential purchasers. Due to the availability of other
markets and pipeline connections, we do not believe that the loss of any single oil or natural gas
customer would have a material adverse effect on our results of operations or cash flows.
We sell our oil and condensate at the lease to a variety of purchasers at prevailing market
prices under short-term contracts that normally provide for us to receive a market based price,
which incorporates regional differentials that include but are not limited to transportation costs
and adjustments for product quality.
Our natural gas production is sold to various purchasers including intrastate pipeline
purchasers, operators of processing plants, and marketing companies under both monthly spot market
contracts and multi-year arrangements. The vast majority of our natural gas sales are based on
related natural gas index pricing. In some cases, our gas is processed at a plant and we receive a
percentage of the value the plant operator receives from the resale of the natural gas liquids
recovered and the remaining residue gas.
Since most of our oil and natural gas production is sold under price sensitive or spot market
contracts, the revenues generated by our operations are highly dependent upon the prices of and
demand for oil and natural gas. The price we receive for our oil and natural gas production
depends upon numerous factors beyond our control, including but not limited to seasonality,
weather, competition, the condition of the United States economy, foreign imports, political
conditions in other oil-producing and natural gas-producing countries, the actions of the
Organization of Petroleum Exporting Countries, and domestic government regulation, legislation and
policies. See Item 1A. Risk Factors Oil and natural gas prices are volatile and thus could be subject to further
reduction, which would adversely affect our results and the price of our common stock.
Furthermore, a decrease in the price of oil and natural gas could have an adverse effect on the
carrying value of our proved reserves and on our revenues, profitability and cash flow. See Item
1A. Risk Factors Lower oil and natural gas prices may cause us to record ceiling limitation
writedowns, which would reduce our stockholders equity.
Although we are not currently experiencing any significant involuntary curtailment of our oil
or natural gas production, market, economic and regulatory factors may in the future materially
affect our ability to sell our oil or natural gas production. See Item 1A. Risk Factors The
marketability of our oil and natural gas production depends on services and facilities that we
typically do not own or control. The failure or inaccessibility of any such services or facilities
could affect market based prices or result in a curtailment of production and revenues.
Competition
The oil and natural gas industry is highly competitive in all phases. We encounter
competition from other oil and natural gas companies in all areas of operation, including the
acquisition of seismic and leasing options on oil and natural gas properties to the exploration and
development of those properties. Our competitors include major integrated oil and natural gas
companies, numerous independent oil and natural gas companies, individuals and drilling and income
programs. Many of our competitors are large, well established companies that have substantially
larger operating staffs and greater capital resources than we do. Such companies may be able to
pay more for seismic and lease options on oil and natural gas properties and exploratory prospects
and to define, evaluate, bid for and purchase a greater number of properties and prospects than our
financial or human resources permit. Our ability to acquire additional properties and to discover
reserves in the future will depend upon our ability to evaluate and select suitable properties and
to consummate transactions in a highly competitive environment. See Item 1A. Risk Factors We
face significant competition and many of our competitors have resources in excess of our available
resources.
5
Operating Hazards and Uninsured Risks
Drilling activities are subject to many risks, including the risk that no commercially
productive reservoirs will be encountered. There can be no assurance that the new wells we drill
will be productive or that we will recover all or any portion of our investment. Drilling for oil
and natural gas may involve unprofitable efforts, not only from dry wells, but also from wells that
are productive, but do not produce sufficient net revenues to return a profit after drilling,
operating and other costs. The cost and timing of drilling, completing and operating wells is
often uncertain. Our drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, many of which are beyond our control, including low oil and natural gas prices,
title problems, weather conditions, delays by project participants, compliance with governmental
requirements, shortages or delays in the delivery of equipment and services and increases in the
cost for such equipment and services. Our future drilling activities may not be successful and, if
unsuccessful, such failure may have a material adverse effect on our business, financial condition,
results of operations and cash flows. See Item 1A. Risk Factors Our exploration, development
and drilling efforts and the operation of our wells may not be profitable or achieve our targeted
returns, Item 1A. Risk Factors Exploratory drilling is a speculative activity that may not
result in commercially productive reserves and may require expenditures in excess of budgeted
amounts, Item 1A. Risk Factors Although our oil and natural gas reserve data is independently
estimated, these estimates may still prove to be inaccurate and Item 1A. Risk Factors The lack
of availability or high cost of drilling rigs, equipment, supplies, insurance, personnel and oil
field services could adversely affect our ability to execute our exploration and development plans
on a timely basis and within our budget.
Our operations are subject to hazards and risks inherent in drilling for and producing and
transporting oil and natural gas, such as fires, natural disasters, explosions, encountering
formations with abnormal pressures, blowouts, craterings, pipeline ruptures and spills, any of
which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and
other damage to our properties and those of others. We maintain insurance against some but not all
of the risks described above. In particular, the insurance we maintain does not cover claims
relating to failure of title to oil and natural gas leases, loss of surface equipment at well
locations, trespass during 3-D survey acquisition or surface damage attributable to seismic
operations, business interruption, loss of revenue due to low commodity prices or loss of revenues
due to well failure. Furthermore, in certain circumstances in which insurance is available, we may
not purchase it. The occurrence of an event that is not covered, or not fully covered by insurance
could have a material adverse effect on our business, financial condition, results of operations
and cash flows in the period such event may occur. See Item 1A. Risk Factors We are subject to
various operating and other casualty risks that could result in liability exposure or the loss of
production and revenues and Item 1A. Risk Factors We may not have enough insurance to cover all
of the risks we face, which could result in significant financial exposure.
Governmental Regulation
Our oil and natural gas exploration, production, transportation and marketing activities are
subject to extensive laws, rules and regulations promulgated by federal and state legislatures and
agencies, including but not limited to the Federal Energy Regulatory Commission (FERC), the
Environmental Protection Agency (EPA), the Bureau of Land Management (BLM), the Texas Commission on
Environmental Quality (TCEQ), the Texas Railroad Commission (TRRC), the Louisiana Department of
Natural Resources (LDNR), the Industrial Commission of North Dakota (NDIC), the Oklahoma
Corporation Commission (OCC), the Wyoming Oil and Gas Conservation Commission (WOGCC), the Montana
Board of Oil and Gas Conservation (MBOGC) and similar type commissions within these states and of
the other states in which we do business. Failure to comply with such laws, rules and regulations
can result in substantial penalties, including the delay or stopping of our operations. The
legislative and regulatory burden on the oil and natural gas industry increases our cost of doing
business and affects our profitability. See Item 1A. Risk Factors We are subject to various
governmental regulations and environmental risks that may cause us to incur substantial costs.
6
Although we do not own or operate any pipelines or facilities that are directly regulated by
FERC, its regulation of third party pipelines and facilities could indirectly affect our ability to
transport or market our production. Moreover, FERC has in the past, and could in the future,
impose price controls on the sale of natural gas. We believe we are in substantial compliance with
all applicable laws and regulations; however, we are unable to predict the future cost or impact of
complying with such laws and regulations because they are frequently amended, interpreted and
reinterpreted.
The states of Texas, Oklahoma, Louisiana, Wyoming, North Dakota, Montana and most other
states, as well as the federal government when operating on federal or Indian lands, require
permits for drilling operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and natural gas. These governmental
authorities also have statutes or regulations addressing conservation matters, including provisions
for the unitization or pooling of oil and natural gas properties, the establishment of maximum
rates of production from wells and the regulation of spacing, plugging and abandonment of such
wells.
Environmental Matters
Our operations and properties are, like the oil and natural gas industry in general, subject
to extensive and changing federal, state and local laws and regulations relating to both
environmental protection, including the generation, storage, handling, emission, transportation and
discharge of materials into the environment, and safety and health. The recent trend in
environmental legislation and regulation is generally toward stricter standards, and this trend is
likely to continue. These laws and regulations may require a permit or other authorization before
construction or drilling commences and for certain other activities; limit or prohibit access,
seismic acquisition, construction, drilling and other activities on certain lands lying within
wilderness and other protected areas; impose substantial liabilities for pollution resulting from
our operations; and require the reclamation of certain lands.
The permits required for many of our operations are subject to revocation, modification and
renewal by issuing authorities. Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines, injunctions, or both. In the opinion of
management, we are in substantial compliance with current applicable environmental laws and
regulations, and we have no material commitments for capital expenditures to comply with existing
environmental requirements. Nevertheless, changes in existing environmental laws and regulations
or in interpretations thereof could have a significant impact on us, as well as the oil and natural
gas industry in general. The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) and comparable state statutes impose strict and arguably joint and several liabilities on
owners and operators of certain sites and on persons who disposed of or arranged for the disposal
of hazardous substances found at such sites. It is not uncommon for the 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. The Resource Conservation and Recovery Act
(RCRA) and comparable state statutes govern the disposal of solid waste and hazardous waste and
authorize imposition of substantial fines and penalties for noncompliance. Although CERCLA
currently excludes petroleum from its definition of hazardous substance, state laws affecting our
operations impose clean-up liability relating to petroleum and petroleum related products. In
addition, although RCRA classifies certain oil field wastes as non-hazardous, such exploration
and production wastes could be reclassified as hazardous wastes, thereby making such wastes subject
to more stringent handling and disposal requirements.
Federal regulations require certain owners or operators of facilities that store or otherwise
handle oil, such as us, to prepare and implement spill prevention, control countermeasure and
response plans relating to the possible discharge of oil into surface waters. The Oil Pollution
Act of 1990 (OPA) contains numerous requirements relating to the prevention of and response to oil
spills into waters of the United States. For onshore and offshore facilities that may affect
waters of the United States, the OPA requires an operator to demonstrate financial responsibility.
Regulations are currently being developed under federal and state laws concerning oil pollution
prevention and other matters that may impose additional regulatory burdens on us. In addition, the
Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into
surface waters or to construct facilities in wetland areas. The Clean Air Act of 1970 and its
subsequent amendments in 1990 and 1997 also impose permit requirements and necessitate certain
restrictions on point source emissions of volatile organic carbons (nitrogen oxides and sulfur
dioxide) and particulates with respect to certain of our operations. We are required to maintain
such permits or meet general permit requirements. The EPA and designated state agencies have in
place regulations
concerning discharges of storm water runoff and stationary sources of air emissions. These
programs require covered facilities to obtain individual permits, participate in a group or seek
coverage under an EPA general permit. Most agencies recognize the unique qualities of oil and
natural gas exploration and production operations. A number of agencies including but not limited
to the EPA, the BLM, the TCEQ, the LDNR, the NDIC, the OCC, the WOGCC, the MBOGC and similar
commissions within these states and of other states in which we do business have adopted regulatory
guidance in consideration of the operational limitations on these types of facilities and their
potential to emit pollutants. We believe that we will be able to obtain, or be included under,
such permits, where necessary, and to make minor modifications to existing facilities and
operations that would not have a material effect on us.
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In addition to the aforementioned regulatory agencies, there are various federal and state
programs that regulate conservation and development of coastal resources. The federal Coastal Zone
Management Act (CZMA) was passed to preserve and, where possible, restore the natural resources of
the United States coastal zone. The CZMA provides for federal grants for the state management
programs that regulate land use, water use and coastal development.
The Texas Coastal Coordination Act (CCA) provides for coordination among local and state
authorities to protect coastal resources through regulating land use, water, and coastal
development and establishes the Texas Coastal Management Program that applies in the nineteen
counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review of
state and federal agency rules and agency actions for consistency with the goals and policies of
the Coastal Management Plan. This review may affect agency permitting and may add a further
regulatory layer to some of our projects.
The Louisiana Coastal Zone Management Program (LCZMP) was established to protect, develop and,
where feasible, restore and enhance coastal resources of the state. Under the LCZMP, coastal use
permits are required for certain activities, even if the activity only partially infringes on the
coastal zone. Among other things, projects involving use of state lands and water bottoms, dredge
or fill activities that intersect with more than one body of water, mineral activities, including
the exploration and production of oil and natural gas, and pipelines for the gathering,
transportation or transmission of oil, natural gas and other minerals require such permits.
General permits, which entail a reduced administrative burden, are available for a number of
routine oil and gas activities. The LCZMP and its requirement to obtain coastal use permits may
result in additional permitting requirements and associated project schedule constraints.
See Item 1A. Risk Factors We are subject to various governmental regulations and
environmental risks that may cause us to incur substantial costs.
Climate Change
Climate change has become the subject of an important public policy debate. Climate change
remains a complex issue, with some scientific research suggesting that an increase in greenhouse gas emissions
(GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and
production industry is a source of certain GHGs, namely carbon dioxide and methane, and future
restrictions on the combustion of fossil fuels or the venting of natural gas could have a
significant impact on our future operations. See Item 1A. Risk
Factors The adoption of climate change legislation by Congress
could result in increased operating costs and reduced demand for the
oil and natural gas we produce.
Impact of Legislation and Regulation. The commercial risk associated with the exploration and
production of fossil fuels lies in the uncertainty of government-imposed climate change
legislation, including cap and trade schemes, and regulations that may affect us, our suppliers,
and our customers. The cost of meeting these requirements may have an adverse impact on our
financial condition, results of operations and cash flows, and could reduce the demand for our
products.
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Climate change legislation and regulations have been adopted by many states in the US;
however, legislation and regulations have not been enacted at the federal level in the US or all
states, although Congress and several states are considering adopting climate change legislation.
The current state of development of many state and federal climate change regulatory initiatives in
areas where we operate makes it difficult to predict with certainty the future impact on us,
including accurately estimating the related compliance costs that we may incur.
Indirect
Consequences of Regulation or Business Trends. We believe there
are risks arising from the
global response to climate change. See Item 1A. Risk Factors The adoption of climate change
legislation by Congress could result in increased operating costs and reduced demand for the oil
and natural gas we produce.
Physical Impacts of Climate Change on our Costs and Operations. There has been public
discussion that climate change may be associated with extreme weather conditions such as more
intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels.
Extreme weather conditions increase our costs, and damage resulting from extreme weather may not be
fully insured. However, the extent to which climate change may lead to increased storm or weather
hazards affecting our operations is difficult to identify at this time.
9
Formation
We were incorporated in the State of Delaware on February 25, 1997.
Facilities
Our principal executive offices are located in Austin, Texas, where we lease approximately
34,330 square feet of office space at 6300 Bridge Point Parkway, Building 2, Suite 500, Austin,
Texas 78730.
Employees
As of December 31, 2009, we had 71 full-time employees and 1 part-time employee. As of the end
of 2009, none of our employees were represented by labor unions and we believe relations with them
are good.
Website Access
We make available, free of charge through our website, www.bexp3d.com, our annual report on
Form 10-K, quarterly reports on Form 10-Q, current reports on form 8-K, and all amendments to those
reports as soon as reasonably practicable after such material is electronically filed with the
Securities and Exchange Commission. Information on our website is not a part of this report.
You should carefully consider the following risk factors, in addition to the other information
set forth in this report. Each of these risk factors could adversely affect our business, operating
results and financial condition.
Oil and natural gas prices are volatile and thus could be subject to further reduction, which would
adversely affect our results and the price of our common stock.
Our revenues, operating results and future rate of growth depend highly upon the prices we
receive for our oil and natural gas production. Historically, the markets for oil and natural gas
have been volatile and are likely to continue to be volatile in the future.
The NYMEX daily settlement price for the prompt month oil contract during 2009 ranged from a
high of $81.37 per barrel to a low of $33.98 per barrel. The NYMEX daily settlement price for the
prompt month oil contract in 2008 ranged from a high of $145.29 per barrel to a low of $33.87 per
barrel. In 2007, the same index ranged from a high of $98.18 per barrel to a low of $50.48 per
barrel.
The NYMEX daily settlement price for the prompt month natural gas contract during 2009 ranged
from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu. The NYMEX daily settlement price for
the prompt month natural gas contract in 2008 ranged from a high of $13.58 per MMBtu to a low of
$5.29 per MMBtu. In 2007, the same index ranged from a high of $8.64 per MMBtu to a low of $5.38
per MMBtu.
The markets and prices for oil and natural gas depend on numerous factors beyond our control.
These factors include demand for oil and natural gas, which fluctuate with changes in market and
economic conditions and other factors, including:
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worldwide and domestic supplies of oil and natural gas; |
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actions taken by foreign oil and natural gas producing nations; |
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political conditions and events (including instability or armed conflict) in
oil-producing or natural gas producing regions; |
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the level of global and domestic oil and natural gas inventories; |
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the price and level of foreign imports including liquefied natural gas imports; |
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the level of consumer demand; |
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the price and availability of alternative fuels; |
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the availability of pipeline or other takeaway capacity; |
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domestic and foreign governmental regulations and taxes; and |
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the overall worldwide and domestic economic environment. |
Significant declines in oil and natural gas prices for an extended period may have the
following effects on our business:
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adversely affect our financial condition, liquidity, ability to finance planned capital
expenditures and results of operations; |
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reduce the amount of oil and natural gas that we can produce economically; |
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cause us to delay or postpone some of our capital projects; |
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reduce our revenues, operating income and cash flow; |
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reduce the carrying value of our oil and natural gas properties; and |
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limit our access to sources of capital, such as equity and long-term debt. |
The ongoing financial uncertainty could negatively impact the prices for oil and natural gas, limit
access to the credit and equity markets, increase the cost of capital, and may have other negative
consequences that we cannot predict.
The ongoing financial uncertainty in the U.S. could create financial challenges if conditions
do not improve. Our internally generated cash flow, our Senior Credit Facility and cash on hand
historically have not been sufficient to fund all of our expenditures, and we have relied on the
capital markets and sales of non-core assets to provide us with additional capital. Our ability to
access the capital markets may be restricted at a time when we would like, or need, to raise
capital. If our cash flow from operations is less than anticipated and our access to capital is
restricted, we may be required to reduce our operating and capital budget, which could have a
material adverse effect on our results and future operations. Ongoing uncertainty may also reduce
the values we are able to realize in asset sales or other transactions we may engage in to raise
capital, thus making these transactions more difficult to consummate and less economic.
Additionally, demand for oil and natural gas may deteriorate further and result in lower prices for
oil and natural gas, which could have a negative impact on our revenues. Lower prices could also
adversely affect the collectability of our trade receivables and cause our commodity hedging
arrangements to be ineffective if our counterparties are unable to perform their obligations.
Our level of indebtedness may adversely affect our cash available for operations, which would limit
our growth, our ability to make interest and principal payments on our indebtedness as they become
due and our flexibility to respond to market changes.
As of December 31, 2009, we had indebtedness of $160 million outstanding under our 9 5/8%
Senior Notes due 2014 (the Senior Notes) and $10.1 million of Series A preferred stock. Our level
of indebtedness will have several important effects on our operations, including:
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we will dedicate a portion of our cash flow from operations to the payment of interest
on our indebtedness and to the payment of our other current obligations and will not have
these cash flows available for other purposes; |
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our debt agreements limit our ability to borrow additional funds or dispose of assets
and may affect our flexibility in planning for, and reacting to, changes in business
conditions; |
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our ability to obtain additional financing in the future for working capital, capital
expenditures, acquisitions, general corporate purposes or other purposes may be impaired; |
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we may be more vulnerable to economic downturns and our ability to withstand sustained
declines in oil and natural gas prices may be impaired; |
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since outstanding balances under our Senior Credit Facility are subject to variable
interest rates, we are vulnerable to increases in interest rates; and |
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our flexibility in planning for or reacting to changes in market conditions may be
limited. |
11
Our ability to meet our debt obligations and reduce our level of indebtedness depends on
future performance. General economic conditions, oil and natural gas prices and financial,
business and other factors will affect our operations and our future performance. Many of these
factors are beyond our control and we may not be able to generate sufficient cash flow to pay the
interest on our debt. In addition, borrowings and equity financing may not be available to pay or
refinance such debt.
The indenture governing the Senior Notes and the documents governing our Senior Credit Facility
impose significant operating and financial restrictions, which may prevent us from capitalizing on
business opportunities and taking some actions.
The indenture governing the Senior Notes and the documents governing our Senior Credit
Facility contain customary restrictions on our activities, including covenants that restrict our
and our subsidiaries ability to:
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pay dividends on, redeem or repurchase stock; |
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make specified types of investments; |
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apply net proceeds from certain asset sales; |
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engage in transactions with our affiliates; |
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engage in sale and leaseback transactions; |
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restrict dividends or other payments from subsidiaries; |
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sell equity interests of subsidiaries; and |
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sell, assign, transfer, lease, convey or dispose of assets. |
Our indenture contains certain incurrence-based covenants that limit our ability to incur debt
and engage in other transactions. One of these covenants incorporates the net present value of our
proved reserves calculated based on SEC rules. Our ability to increase our borrowings in 2010
will depend, in part, on prices for oil and natural gas utilized in our year-end 2009 reserve
report. Our Senior Credit Facility also requires us to meet a minimum current ratio, a minimum
interest coverage ratio, a net leverage ratio and a liquidity requirement. We may not be able to
maintain or comply with these ratios, and if we fail to be in compliance with these tests, we will
not be able to borrow funds under our Senior Credit Facility, which would make it difficult for us
to operate our business.
The restrictions in the indenture governing the Senior Notes and the documents governing our
Senior Credit Facility may prevent us from taking actions that we believe would be in the best
interest of our business, and may make it difficult for us to successfully execute our business
strategy or effectively compete with companies that are not similarly restricted. We may also
incur future debt obligations that might subject us to additional restrictive covenants that could
affect our financial and operational flexibility. We cannot assure you that we will be granted
waivers or amendments to these agreements if for any reason we are unable to comply with these
agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all.
The breach of any of these covenants and restrictions could result in a default under the
indenture governing the Senior Notes or under the documents governing our Senior Credit Facility.
An event of default under our debt agreements would permit some of our lenders to declare all
amounts borrowed from them to be due and payable. If we are unable to repay such indebtedness,
lenders having secured obligations, such as the lenders under our Senior Credit Facility, could
proceed against the collateral securing the debt. Because the indenture governing the Senior Notes
and the documents governing our Senior Credit Facility have customary cross-default provisions, if
the indebtedness under the Senior Notes or under our Senior Credit Facility or any of our other
facilities is accelerated, we may be unable to repay or finance the amounts due.
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Availability under our Senior Credit Facility is based on a borrowing base which is subject to
redetermination by our lenders. If our borrowing base is reduced, we may be required to repay
amounts outstanding under our Senior Credit Facility.
Under the terms of our Senior Credit Facility, our borrowing base is subject to semi-annual
redetermination by our lenders based on their valuation of our proved reserves and their internal
criteria. In addition to such semi-annual determinations, our lenders may request one additional borrowing base redetermination
during any 12-month period. Our borrowing base is also subject to reduction if we monetize certain
of our hedging transactions. In the event the amount outstanding under our Senior Credit Facility at
any time exceeds the borrowing base at such time, we may be required to repay a portion of our
outstanding borrowings over a period no longer than six months. If we do not have sufficient funds
on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance
our Senior Credit Facility, sell assets or sell additional shares of common stock. We may not be
able obtain such financing or complete such transactions on terms acceptable to us, or at all.
Failure to make the required repayment could result in a default under our Senior Credit Facility,
which could adversely affect our business, financial condition and results or operations. Our
borrowing base is currently set at $110 million until the next borrowing base redetermination
provided for in the Senior Credit Facility, which is scheduled for May 2010.
We may incur additional indebtedness. This could further exacerbate the risks associated with our
substantial leverage.
We may incur substantial additional indebtedness in the future. The indenture governing our
senior notes and documents governing our Senior Credit Facility contain restrictions on our ability
to incur indebtedness. These restrictions, however, are subject to a number of qualifications and
exceptions, and under certain circumstances we could incur substantial additional indebtedness in
compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring
obligations that do not constitute Indebtedness or Debt under the indenture and the Senior
Credit Facility, respectively. If we incur indebtedness above our current debt levels, the related
risks that we now face could intensify and we may not be able to meet all our debt obligations.
Failure to meet these obligations could result in a default under our debt documents, which could
adversely affect our business, financial condition and results of operations.
To service our indebtedness we will require a significant amount of cash. Our ability to generate
cash depends on many factors beyond our control. Failure to generate sufficient cash to service
our indebtedness could adversely affect our business, financial condition and results of
operations.
Our ability to meet our debt obligations and other expenses will depend on our future
performance, which will be subject to general economic, financial, competitive, legislative,
regulatory and other factors that are beyond our control. We cannot assure you that our business
will generate sufficient cash flow from operations or that future borrowings will be available to
us under our Senior Credit Facility or otherwise in an amount sufficient to enable us to pay our
indebtedness or to fund our other liquidity needs.
If we are unable to meet our debt service obligations, we may be required to seek a waiver or
amendment from our debt holders, refinance such debt obligations or sell assets or additional
shares of common stock. We may not be able obtain such financing or complete such transactions on
terms acceptable to us, or at all. Failure to meet our debt obligations could result in a default
under the agreements governing our indebtedness. An event of default under our debt agreements
would permit some of our lenders to declare all amounts borrowed from them to be due and payable.
If we are unable to repay such indebtedness, lenders having secured obligations, such as the
lenders under our Senior Credit Facility, could proceed against the collateral securing the debt.
Because the indenture governing the Senior Notes and the documents governing our Senior Credit
Facility have customary cross-default provisions, if the indebtedness under the Senior Notes or
under our Senior Credit Facility or any of our other facilities is accelerated, we may be unable to
repay or finance the amounts due.
Our hedging activities may prevent us from benefiting from price increases and may expose us to
other risks.
In an attempt to reduce our sensitivity to energy price volatility and in particular to
downward price movements, we enter into hedging arrangements with respect to a portion of expected
production, such as the use of derivative contracts that generally result in a range of minimum and
maximum price limits or a fixed price over a specified time period.
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Our hedging activities expose us to the risk of financial loss in certain circumstances. For
example, if we do not produce our oil and natural gas reserves at rates equivalent to our
derivative position, we would be required to satisfy our obligations under those derivative
contracts on potentially unfavorable terms without the ability to offset that risk through sales of
comparable quantities of our own production. Additionally, because the terms of our
derivative contracts are based on assumptions and estimates of numerous factors such as cost of
production and pipeline and other transportation and marketing costs to delivery points,
substantial differences between the prices we receive pursuant to our derivative contracts and our
actual results could harm our anticipated profit margins and our ability to manage the risk
associated with fluctuations in oil and natural gas prices. We also could be financially harmed if
the counterparties to our derivative contracts prove unable or unwilling to perform their
obligations under such contracts. Additionally, in the past, some of our derivative contracts
required us to deliver cash collateral or other assurances of performance to the counterparties if
our payment obligations exceeded certain levels. Future collateral requirements are uncertain but
will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.
The results of our planned drilling in the Bakken and Three Forks objectives, an emerging play with
limited drilling and production history, are subject to more uncertainties than our drilling
program in the more established formations and may not meet our expectations for reserves or
production.
We have recently begun drilling wells in the Bakken and Three Forks objectives. Part of our
drilling strategy to maximize recoveries from the Bakken and Three Forks objectives involves the
drilling of horizontal wells using completion techniques that have proven to be successful in other
shale formations. Our experience with horizontal drilling of the Bakken and Three Forks objectives
to date, as well as the industrys drilling and production history in the formation, is limited.
The ultimate success of these drilling and completion strategies and techniques in this formation
will be better evaluated over time as more wells are drilled and longer term production profiles
are established. In addition, based on reported decline rates in these formations in other areas
and in other shale formations, we estimate the average monthly rates of production should decline
by approximately 70% during the first twelve months of production. Actual decline rates may differ
significantly. Accordingly, the results of our future drilling in the emerging Bakken and Three
Forks objectives are more uncertain than drilling results in the other formations with established
reserves and production histories.
Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of
drilling rigs and other services may be more challenging in new or emerging plays. If our drilling
results are less than anticipated or we are unable to execute our drilling program because of
capital constraints, lease expirations, access to gathering systems and takeaway capacity or
otherwise, and/or oil and natural gas prices remain depressed or decline further, the return on our
investment in these areas may not be as attractive as we anticipate and we could incur material
writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the
future.
The proposed United States federal budget for fiscal year 2010 and other pending legislation
contain certain provisions that, if passed as originally submitted, will have an adverse effect on
our financial position, results of operations, and cash flows.
In February 2009, the Obama administration released its budget proposals for the fiscal year
2010, which included numerous proposed tax changes. In April 2009, legislation was introduced to
further these objectives. The proposed budget and legislation would repeal many tax incentives and
deductions that are currently used by U.S. oil and gas companies and impose new taxes. Among
others, the provisions include: elimination of the ability to fully deduct intangible drilling
costs in the year incurred; repeal of the percentage depletion deduction for oil and gas
properties; repeal of the manufacturing tax deduction for oil and gas companies; increase in the
geological and geophysical amortization period for independent producers; and implementation of a
fee on non-producing leases located on federal lands. Should some or all of these provisions
become law our taxes could increase, potentially significantly, after net operating losses are
exhausted, which would have a negative impact on our net income and cash flows. This could also
reduce our drilling activities. Although these proposals were made approximately one year ago,
none have been voted on or become law, however, it is still the Obama Administrations stated
intention to enact these provisions in 2010. We do not know the ultimate impact these proposed
changes may have on our business.
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We depend on our key management personnel and technical experts and the loss any of these
individuals could adversely affect our business.
If we lose the services of our key management personnel, technical experts or are unable to
attract additional qualified personnel, our business, financial condition, results of operations,
development efforts and ability to grow could suffer. We have assembled a team of engineers,
geologists and geophysicists who have considerable experience in applying advanced horizontal
drilling and completion and 3-D seismic imaging technology to explore for and to develop oil and
natural gas. We depend upon the knowledge, skill and experience of these experts to assist us in
improving the performance and reducing the risks associated with our participation in oil and
natural gas exploration and development projects. In addition, the success of our business
depends, to a significant extent, upon the abilities and continued efforts of our management,
particularly Ben M. Brigham, our Chief Executive Officer, President and Chairman of the Board. We
have an employment agreement with Mr. Brigham, but do not have an employment agreement with any of
our other employees.
Lower oil and natural gas prices may cause us to record ceiling limitation writedowns, which would
reduce our stockholders equity.
We use the full cost method of accounting for our oil and natural gas investments.
Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas
properties. Under full cost accounting rules, the net capitalized cost of oil and natural gas
properties may not exceed a ceiling limit that is based upon the present value of estimated
future net revenues from proved reserves, discounted at 10%, plus the lower of the cost or fair
market value of unproved properties. If net capitalized costs of oil and natural gas properties
exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a
ceiling limitation writedown. The risk that we will experience a ceiling limitation writedown
increases when oil and gas prices are depressed or if we have substantial downward revisions in
estimated proved reserves. Based on oil and gas prices in effect on March 31, 2009 ($3.63 per
MMBtu for Henry Hub gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for
differentials), the unamortized cost of our oil and gas properties
exceeded the ceiling limit. As
such, we recorded a $114.8 million ($71.9 million after tax) impairment to our oil and gas
properties at March 31, 2009. Based on oil and gas prices in effect on December 31, 2008 ($5.71
per MMBtu for Henry Hub gas and $44.60 per barrel for West Texas Intermediate oil, adjusted for
differentials), the unamortized cost of our oil and gas properties exceeded the ceiling limit. As
such, we recorded a $237.2 million ($148.6 million after tax) impairment to our oil and gas
properties at December 31, 2008. We may be required to recognize additional pre-tax non-cash
impairment charges in the future reporting periods if market prices for oil or natural gas decline.
We may have difficulty financing our planned capital expenditures, which could adversely affect our
business.
We make and hope to continue to make substantial capital expenditures in our exploration and
development projects. Without additional capital resources, our drilling and other activities may
be limited and our business, financial condition and results of operations may suffer. We may not
be able to secure additional financing on reasonable terms or at all, and financing may not
continue to be available to us under our existing or new financing arrangements. If additional
capital resources are unavailable, we may curtail our drilling, development and other activities or
be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or
sale could have a material adverse effect on our business, financial condition and results of
operation.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next
several years unless production is established on units containing the acreage or the leases are
extended.
As of December 31, 2009, we had mineral leases on approximately 282,584 net acres in the
Williston Basin which we believe are prospective for the Bakken and/or Three Forks. A significant
portion of the acreage is not currently held by production. Unless production in paying quantities
is established on units containing these leases during their primary terms or we obtain extensions
of the leases, these leases will expire. If our leases expire, we will lose our right to develop
the related properties.
Our drilling plans for these areas are subject to change based upon various factors, including
factors that are beyond our control, including drilling results, oil and natural gas prices, the
availability and cost of capital, drilling
and production costs, availability of drilling services and equipment, gathering system and
pipeline transportation constraints, and regulatory approvals.
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Our exploration, development and drilling efforts and the operation of our wells may not be
profitable or achieve our targeted returns.
We require significant amounts of undeveloped leasehold acreage in order to further our
development efforts. Exploration, development, drilling and production activities are subject to
many risks, including the risk that commercially productive reservoirs will not be discovered. We
invest in property, including undeveloped leasehold acreage, which we believe will result in
projects that will add value over time. However, we cannot guarantee that all of our prospects
will result in viable projects or that we will not abandon our initial investments. Additionally,
we cannot guarantee that the leasehold acreage we acquire will be profitably developed, that new
wells drilled by us in provinces that we pursue will be productive or that we will recover all or
any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas
may involve unprofitable efforts, not only from dry wells, but also from wells that are productive
but do not produce sufficient net reserves to return a profit after deducting operating and other
costs. Wells that are profitable may not achieve our targeted rate of return. Our ability to
achieve our target results is dependent upon the current and future market prices for oil and
natural gas, costs associated with producing oil and natural gas and our ability to add reserves at
an acceptable cost. Additionally, we rely to some extent on 3-D seismic data and other advanced
technologies in identifying leasehold acreage prospects and in conducting our exploration
activities. These technologies we use do not allow us to know conclusively prior to the
acquisition of leasehold acreage or the drilling of a well whether oil or natural gas is present or
may be produced economically.
In addition, we may not be successful in implementing our business strategy of controlling and
reducing our drilling and production costs in order to improve our overall return. The cost of
drilling, completing and operating a well is often uncertain and cost factors can adversely affect
the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit,
delay or cancel drilling operations as a result of a variety of factors, including:
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unexpected drilling conditions; |
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pressure or irregularities in formations; |
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equipment failures or accidents; |
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adverse weather conditions; |
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compliance with governmental requirements; and |
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shortages or delays in the availability of drilling rigs and the delivery of equipment. |
Exploratory drilling is a speculative activity that may not result in commercially productive
reserves and may require expenditures in excess of budgeted amounts.
Our future rate of growth greatly depends on the success of our exploratory drilling program.
Exploratory drilling involves a higher degree of risk that we will not encounter commercially
productive oil or natural gas reservoirs than developmental drilling. We may not be successful in
our future drilling activities because, even with the use of advanced horizontal drilling and
completion techniques, 3-D seismic and other advanced technologies, exploratory drilling is a
speculative activity.
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Although our oil and natural gas reserve data is independently estimated, these estimates may still
prove to be inaccurate.
Our proved reserve estimates are prepared each year by Cawley, Gillespie & Associates, Inc.,
an independent petroleum consulting firm. In conducting its evaluation, the engineers and
geologists of Cawley, Gillespie & Associates, Inc. evaluate our properties and independently
develop proved reserve estimates. There are numerous uncertainties and risks that are inherent in
estimating quantities of oil and natural gas reserves and projecting future rates of production and
timing of development expenditures as many factors are beyond our control. We incorporate many
factors and assumptions into our estimates including:
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expected reservoir characteristics based on geological, geophysical and engineering
assessments; |
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future production rates based on historical performance and expected future operating
and investment activities; |
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future oil and gas prices and quality and location differentials; and |
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future development and operating costs. |
Although we believe the Cawley, Gillespie & Associates, Inc. reserve estimates are reasonable
based on the information available to them at the time they prepare their estimates, our actual
results could vary materially from these estimated quantities of proved oil and natural gas
reserves (in the aggregate and for a particular location), production, revenues, taxes and
development and operating expenditures. In addition, these estimates of proved reserves may be
subject to downward or upward revision based upon production history, results of future exploration
and development, prevailing oil and natural gas prices, operating and development costs and other
factors.
Finally, recovery of proved undeveloped reserves generally requires significant capital
expenditures and successful drilling operations. At December 31, 2009, approximately 63% of our
estimated proved reserves were classified as undeveloped. At December 31, 2009, we estimated that
it would require additional capital expenditures of approximately $266.7 million to develop our
proved undeveloped reserves. Our reserve estimates assume that we can and will make these
expenditures and conduct these operations successfully, which may not occur.
We need to replace our reserves at a faster rate than companies whose reserves have longer
production periods. Our failure to replace our reserves would result in decreasing reserves and
production over time.
In general, production from oil and natural gas properties declines as reserves are depleted,
with the rate of decline depending on reservoir characteristics. Except to the extent we conduct
successful exploration and development activities or acquire properties containing proved reserves,
or both, our proved reserves and production will decline as reserves are produced.
We may not be able to find, develop or acquire additional reserves to replace our current and
future production. Accordingly, our future oil and natural gas reserves and production and
therefore our future cash flow and income, are dependent upon our success in economically finding
or acquiring new reserves and efficiently developing our existing reserves.
Our reserves in the Gulf Coast have high initial production rates followed by steep declines in
production, resulting in a reserve life for wells in this area that is shorter than the industry
average. This production volatility has impacted and, in the future, may continue to impact our
quarterly and annual production levels.
We generally must locate and develop or acquire new oil and natural gas reserves to replace
those being depleted by production. Without successful drilling and exploration or acquisition
activities, our reserves and revenues will decline rapidly. We may not be successful in extending
the reserve life of our properties generally and our Gulf Coast properties in particular. Our
current strategy includes increasing our reserve base through drilling activities in our Rocky
Mountains province and in our other core areas, which have historically had longer-lived reserves.
Our existing and future exploration and development projects may not result in significant
additional reserves and we may not be able to drill productive wells at economically viable costs.
Our future cash flows are subject to a number of variables, such as the level of production
from existing wells, prices of oil and natural gas and our success in finding and producing new
reserves. If our revenues were to decrease as a result of lower oil and natural gas prices,
decreased production or otherwise, and our access to capital were limited, we would have a reduced
ability to replace our reserves or to maintain production at current levels, potentially resulting
in a decrease in production and revenue over time.
17
Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable
quantities or quantities sufficient to meet our targeted rate of return.
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 conclusively
predict in advance of drilling and testing whether any particular drilling location will yield
oil or natural gas in sufficient quantities to recover our drilling or completion costs or to be
economically viable. Our use of seismic data and other technologies and the study of producing
fields in the same area will not enable us to know conclusively prior to drilling whether oil and
natural gas will be present or, if present, whether oil and natural gas will be present in
commercial quantities. The analysis that we perform using data from other wells, more fully
explored prospects and/or producing fields may not be useful in predicting the characteristics and
potential reserves associated with our drilling locations. As a result, we may not find
commercially viable quantities of oil and natural gas and, therefore, we may not achieve a targeted
rate of return or have a positive return on investment.
The lack of availability or high cost of drilling rigs, equipment, supplies, insurance, personnel
and oil field 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, insurance or qualified personnel. During these periods, the costs and
delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand
for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service
increases. If increasing levels of exploration and production result in response to strong prices
of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these
services will likely increase, while the quality of these services may suffer. If the lack of
availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel
were particularly severe in North Dakota, Montana, Texas, Southern Louisiana, or Oklahoma, we could
be materially and adversely affected because our operations and properties are concentrated in
those areas.
The marketability of our oil and natural gas production depends on services and facilities that we
typically do not own or control. The failure or inaccessibility of any such services or facilities
could affect market based prices or result in a curtailment of production and revenues.
The marketability of our oil and natural gas production depends in part upon the availability,
proximity and capacity of natural gas gathering and transportation systems, pipelines and
processing facilities. We generally deliver oil at our leases under short-term contracts.
Counterparties to our short-term contracts rely on access to regional transportation systems and
pipelines. If transportation systems or pipeline capacity is constrained, we would be required to
find alternative transportation modes, which would impact our market based price, or temporarily
curtail production. We generally deliver natural gas through gas gathering systems and gas
pipelines that we do not own under interruptible or short term transportation agreements. Under
the interruptible transportation agreements, the transportation of our natural gas may be
interrupted due to capacity constraints on the applicable system, for maintenance or repair of the
system, or for other reasons as dictated by the particular agreements. If any of the pipelines or
other facilities become unavailable, we would be required to find a suitable alternative to
transport and process the natural gas, which could increase our costs and reduce the revenues we
might obtain from the sale of the natural gas. For example, in 2008, Hurricanes Gustav and Ike
disrupted our Gulf Coast operations forcing us to temporarily curtail production and delayed
bringing new wells on line. Hurricane Ike forced us to curtail approximately 1.0 MMcfe per day of
production during the third quarter 2008. Furthermore, both Hurricanes Gustav and Ike delayed our
completion operations on our Southern Louisiana wells reducing third quarter 2008 production by an
estimated 1.8 MMcfe per day.
We are subject to various operating and other casualty risks that could result in liability
exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in drilling for and producing and
transporting oil and natural gas, such as:
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formations with abnormal pressures; |
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blowouts, cratering and explosions; and |
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pipeline ruptures and spills. |
Any of these hazards and risks can result in the loss of hydrocarbons, environmental
pollution, personal injury claims and other damage to our properties and the property of others.
18
We may not have enough insurance to cover all of the risks we face, which could result in
significant financial exposure.
We maintain insurance coverage against some, but not all, potential losses in order to protect
against the risks we face. We may elect not to carry insurance if our management believes that the
cost of insurance is excessive relative to the risks presented. If an event occurs that is not
covered, or not fully covered, by insurance, it could harm our financial condition, results of
operations and cash flows. In addition, we cannot fully insure against pollution and environmental
risks.
We cannot control activities on properties we do not operate. Failure to fund capital expenditure
requirements may result in reduction or forfeiture of our interests in some of our non-operated
projects.
We do not operate some of the properties in which we have an interest and we have limited
ability to exercise influence over operations for these properties or their associated costs. As
of December 31, 2009, approximately 26% of our oil and natural gas proved reserves were operated by
other companies. Our dependence on the operator and other working interest owners for these
projects and our limited ability to influence operations and associated costs could materially
adversely affect the realization of our targeted return on capital in drilling or acquisition
activities and our targeted production growth rate. The success and timing of drilling,
development and exploitation activities on properties operated by others depend on a number of
factors that are beyond our control, including the operators expertise and financial resources,
approval of other participants for drilling wells and utilization of technology.
When we are not the majority owner or operator of a particular oil or natural gas project, we
may have no control over the timing or amount of capital expenditures associated with such project.
If we are not willing or able to fund our capital expenditures relating to such projects when
required by the majority owner or operator, our interests in these projects may be reduced or
forfeited.
Our future operating results may fluctuate and significant declines in them would limit our ability
to invest in projects.
Our future operating results may fluctuate significantly depending upon a number of factors,
including:
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prices of oil and natural gas; |
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rates of drilling success; |
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rates of production from completed wells; and |
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the timing and amount of capital expenditures. |
This variability could cause our business, financial condition and results of operations to
suffer. In addition, any failure or delay in the realization of expected cash flows from operating
activities could limit our ability to invest and participate in economically attractive projects.
We face significant competition and many of our competitors have resources in excess of our
available resources.
We operate in the highly competitive areas of oil and natural gas exploration, exploitation,
acquisition and production. We face intense competition from a large number of independent,
technology-driven companies as well as both major and other independent oil and natural gas
companies in a number of areas such as:
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seeking to acquire desirable producing properties or new leases for future exploration; |
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marketing our oil and natural gas production; and |
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seeking to acquire the equipment and expertise necessary to operate and develop those
properties. |
Many of our competitors have financial and other resources substantially in excess of those
available to us. This highly competitive environment could harm our business.
19
We are subject to various governmental regulations and environmental risks that may cause us to
incur substantial costs.
From time to time, in varying degrees, political developments and federal and state laws and
regulations affect our operations. In particular, price controls, taxes and other laws relating to
the oil and natural gas industry, changes in these laws and changes in administrative regulations
have affected and in the future could affect oil and natural gas production, operations and
economics. We cannot predict how agencies or courts will interpret existing laws and regulations
or the effect of these adoptions and interpretations may have on our business or financial
condition.
Our business is subject to laws and regulations promulgated by federal, state and local
authorities, including but not limited to the United States Congress, the FERC, the EPA, the BLM, the TRRC, the TCEQ, the OCC, the
LDNR, the NDIC, the WOGCC and the MBOGC relating to
the exploration for, and the development, production and marketing of, oil and natural gas, as well
as safety matters. Legal requirements are frequently changed and subject to interpretation and we
are unable to predict the ultimate cost of compliance with these requirements or their effect on
our operations. We may be required to make significant expenditures to comply with governmental
laws and regulations. The discharge of oil, natural gas or other pollutants into the air, soil or
water may give rise to significant liabilities on our part to the government and third parties and
may require us to incur substantial costs of remediation.
Our operations are subject to complex federal, state and local environmental laws and
regulations, including CERCLA, RCRA, the Oil Pollution Act of 1990, and the Clean Water Act.
Environmental laws and regulations change frequently, and the implementation of new, or the
modification of existing, laws or regulations could harm us. For example, on June 9, 2009,
companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act of
2009 were introduced in the United States Senate and House of Representatives. These bills would
repeal the exemption for hydraulic fracturing from the federal Safe Drinking Water Act, which would
have the effect of allowing the federal Environmental Protection Agency, commonly referred to as
the EPA, to promulgate regulations requiring permits and implementing potential new requirements on
hydraulic fracturing under the federal Safe Drinking Water Act. This could, in turn, require state
regulatory agencies in states with programs delegated under the Safe Drinking Water Act to impose
additional requirements on hydraulic fracturing operations. In addition, the bills would require
person using hydraulic fracturing, such as us, to disclose the chemical constituents, but not the
proprietary formulas, of their fracturing fluids to a regulatory agency, which would make the
information public via the internet. If this or similar legislation becomes law, it could cause us
to incur substantial compliance costs, and compliance or the consequences of any failure to comply
by us could have a material adverse effect on our financial condition and results of operations.
At this time, it is not possible to estimate the potential impact on our business that may arise if
the federal or state legislation is enacted into law.
The adoption of climate change legislation by Congress could result in increased operating costs
and reduced demand for the oil and natural gas we produce.
In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security
Act of 2009, also known as the Waxman-Markey Bill. The U.S. Senates version, The Clean Energy
Jobs and American Power Act, or the Boxer-Kerry Bill, has been introduced, but has not passed.
Although these bills include several differences that require reconciliation before becoming law,
both bills contain the basic feature of establishing a cap and trade system for restricting
greenhouse gas emissions. Under such system, certain sources of greenhouse gas emissions would be
required to obtain greenhouse gas emission allowances corresponding to their annual emissions of
greenhouse gases. The number of emission allowances issued each year would decline as necessary to
meet overall emission reduction goals. As the number of greenhouse gas emission allowances
declines each year, the cost or value of allowances is expected to escalate significantly. The
ultimate outcome of this legislative
initiative remains uncertain. In addition to the pending climate legislation, the EPA has
issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010,
and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond
measuring and reporting, the EPA issued an Endangerment Finding under section 202(a) of the Clean
Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and
future generations. The EPA has proposed regulation that would require permits for and reductions
in greenhouse gas emissions for certain facilities, and may issue final rules this year. Any laws
or regulations that may be adopted to restrict or reduce emissions of GHGs could require us to
incur increased operating costs, and could have an adverse effect on demand for the oil and natural
gas we produce, depending on the applicability to company operations and the refining, processing,
and use of oil and gas.
20
The market price of our stock is volatile.
The trading price of our common stock and the price at which we may sell securities in the
future are subject to large fluctuations in response to any of the following:
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limited trading volume in our stock; |
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changes in government regulations; |
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quarterly variations in operating results; |
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our involvement in litigation; |
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general market conditions; |
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the prices of oil and natural gas; |
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announcements by us and our competitors; |
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our ability to raise additional funds; and |
Our stock price may decline when our financial results decline or when events occur that are
adverse to us or our industry.
You can expect the market price of our common stock to decline when our financial results
decline or otherwise fail to meet the expectations of the financial community or the investing
public or at any other time when events actually or potentially adverse to us or the oil and
natural gas industry occur. Our common stock price may decline to a price below the price you paid
to purchase your shares of common stock.
We are prohibited from paying dividends on our common stock.
We will retain all future earnings and other cash resources for the future operation and
development of our business. The documents governing our Senior Credit Facility and the indenture
governing our Senior Notes prohibit the payment of dividends. Accordingly, we do not intend to
declare or pay any cash dividends on our common stock in the foreseeable future.
Certain anti-takeover provisions may adversely affect your rights as a stockholder.
Our certificate of incorporation authorizes our Board of Directors to issue up to 10 million
shares of preferred stock without stockholder approval and to set the rights, preferences and other
designations, including voting rights, of those shares as the Board of Directors may determine. In
addition, our Series A preferred stock, the documents governing our senior credit facility and our
indenture governing our Senior Notes contain terms restricting our ability to enter into change of
control transactions, including requirements to redeem or repay upon a change in control our
outstanding Series A preferred stock, the amounts borrowed under our senior credit facility and our
Senior Notes. These provisions, alone or in combination with the other matters described in
the preceding paragraph, may discourage transactions involving actual or potential changes in our
control, including transactions that otherwise could involve payment of a premium over prevailing
market prices to holders of our common stock. We are also subject to provisions of the Delaware
General Corporation Law that may make some business combinations more difficult.
21
Forward-Looking Statements
This report and the documents incorporated by reference in this annual report on Form 10-K
contain forward-looking statements within the meaning of the federal securities laws.
These forward-looking statements include, among others, the following:
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our ability to successfully and economically explore for and develop oil and gas
resources; |
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anticipated trends in our business; |
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our future results of operations; |
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our liquidity and ability to finance our exploration and development activities; |
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market conditions in the oil and gas industry; |
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our ability to make and integrate acquisitions; and |
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the impact of governmental regulation. |
Forward-looking statements are typically identified by use of terms such as may, will,
expect, anticipate, estimate and similar words, although some forward-looking statements may
be expressed differently.
You should be aware that our actual results could differ materially from those contained in
the forward-looking statements. You should consider carefully the statements in this Item 1A. Risk
Factors and other sections of this report, which describe factors that could cause our actual
results to differ from those set forth in the forward-looking statements.
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Item 1B. |
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Unresolved Staff Comments |
None.
Historically, our exploration and development activities have been focused in the Onshore Gulf
Coast, the Anadarko Basin and West Texas. Beginning in late 2005, we began to acquire acreage
within the Williston Basin in North Dakota and Montana and as of December 31, 2009, we have
approximately 453,147 gross and 282,584 net leasehold acres in the
Williston Basin. In late 2007, the
majority of our drilling capital expenditures shifted from our historically active areas in the
Onshore Gulf Coast, the Anadarko Basin and West Texas to the Williston Basin, where we are
currently targeting the Bakken, Three Forks and Red River formations. In 2008, we drilled 53 gross
wells on our Williston Basin acreage investing a total of $117.4 million in drilling, land and
seismic. In 2009, we drilled 54 gross wells on our Williston Basin acreage investing a total of
$53.1 million in drilling, land and seismic. Through year-end 2009, we have invested in excess of
$222 million on drilling, land and seismic in the Williston Basin.
22
In 2009, we spent a total of
approximately $60.0 million on drilling, land and seismic in our
operating areas. During 2010, we plan to spend approximately $183.7 million on drilling 60 gross (27.1 net)
wells as well as drill and complete wells that were in progress at December 31, 2009. We currently
expect to spend approximately $15.6 million on land and seismic and incur $14.8 million for
capitalized costs. See Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations Capital Commitments
Capital Expenditures. The following is a summary of our properties by major province as of
December 31, 2009, unless otherwise noted.
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Rocky |
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Onshore |
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Anadarko |
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West Texas |
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Mountains (a) |
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Gulf Coast |
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Basin |
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& Other |
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Total |
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Capital expenditures for drilling,
land and seismic in 2009 (in
millions) |
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$ |
53.1 |
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$ |
7.4 |
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$ |
(1.2 |
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$ |
0.7 |
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$ |
60.0 |
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Proved Reserves at December 31, 2009 |
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Pre-tax PV10% (in millions) (b) |
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$ |
133.6 |
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$ |
87.7 |
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$ |
13.1 |
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$ |
19.7 |
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$ |
254.1 |
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Oil (MMBbls) |
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13.7 |
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1.7 |
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0.2 |
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1.1 |
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16.6 |
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Natural gas (Bcf) |
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10.4 |
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38.9 |
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16.4 |
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0.7 |
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66.4 |
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Oil equivalents (MMBoe) (c) |
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15.4 |
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8.2 |
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2.9 |
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1.2 |
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27.7 |
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% Oil |
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89 |
% |
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21 |
% |
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6 |
% |
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90 |
% |
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60 |
% |
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Average daily production volumes
(MBoe) (d) |
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1,816 |
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2,194 |
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726 |
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298 |
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5,034 |
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Average daily sales volumes (MBoe)(d) |
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1,770 |
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2,194 |
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726 |
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298 |
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4,988 |
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Productive wells at December 31, 2009 |
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Gross |
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115 |
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76 |
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82 |
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83 |
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356 |
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Net |
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22.9 |
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38.3 |
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21.3 |
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24.6 |
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107.1 |
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3-D Seismic Data (square miles) |
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1,402 |
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4,459 |
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2,381 |
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4,698 |
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12,940 |
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(a) |
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Includes the Williston Basin located in North Dakota and Montana and the Powder River Basin
located in Wyoming. |
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(b) |
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The standardized measure for our proved reserves at December 31, 2009, was $246.5 million.
See - Reconciliation of Standardized Measure to Pre-tax PV10% for a definition of pre-tax
PV10% and a reconciliation of our standardized measure to our pre-tax PV10% value. The prices
used to calculate this measure were $61.18 per barrel of oil and $3.87 per MMbtu of natural
gas. These prices represent the average prices per barrel of oil and per MMbtu of natural gas
at the beginning of each month in the 12-month period prior to the end of the reporting
period. These prices were adjusted to reflect applicable
transportation and quality differentials on a well-by-well basis to
arrive at realized sales prices used to estimate our reserves at this
date. |
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Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
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Average daily production volumes calculated based on 360 day year. Includes approximately
16,475 barrels of oil produced in the Williston Basin during 2009 and recorded as inventory at
year-end 2009. Ending inventory at year end 2008 and 2007 was not material. Adjusting the
production volumes for amounts included in inventory would result in average daily sales
volumes in the Rocky Mountains and in total of 1,770 and 4,988 barrels of oil
equivalent, respectively. |
Rocky Mountains Province
We regularly evaluate opportunities to expand our activities to areas that may offer
attractive exploration and development potential. In late 2005, we began accumulating acreage in
the Williston Basin located in North Dakota and Montana and in early 2006 entered into a joint
venture agreement in the Powder River Basin located in Wyoming. During 2009, we invested
approximately $53.1 million in drilling, land and seismic in the Williston Basin. During 2009, we
spud 54 gross wells in the Williston Basin, with 13 wells completing and three wells drilling at
year-end. In 2009, we did not allocate any capital spending to the Powder River Basin.
Overview of Williston Basin
The Williston Basin is spread across North Dakota, Montana and parts of southern Canada with
the United States portion of the basin encompassing approximately 143,000 square miles. The basin
produces oil and gas from numerous producing horizons including, but not limited to, the Bakken,
Three Forks and Red River formations, which are currently our primary objectives.
23
The Bakken is an unconventional oil shale play at depths of approximately 8,500 to 10,500 feet
that is primarily exploited via horizontal drilling and advanced completion techniques. Advanced
completion techniques include the use of swell packers and multi-stage fracture stimulations, which
help to fracture the shales and increase oil flow to the well bore. To date, much of the Bakken
drilling in North Dakota has occurred east of the Nesson Anticline in and around Mountrail County,
with additional activity south of the Nesson Anticline in Dunn County. In the second half of 2009,
activity accelerated west of the Nesson Anticline in Williams and McKenzie Counties, North Dakota.
The Three Forks is an unconventional carbonate play that lies just below the Bakken. Similar
to the Bakken, the Three Forks is primarily exploited using horizontal drilling and advanced
completion techniques. Drilling in the Three Forks began in mid-2008 and a number of operators,
including us, are targeting this objective. Drilling in this objective is early, but initial
results appear to indicate that the Three Forks is a separate reservoir from the Bakken, which
increases our exposure to oil reserves in the basin. Over time, further drilling of both Bakken
and Three Forks wells in the same sections will help to delineate whether the Bakken and Three
Forks are separate reservoirs.
The Red River is a conventional oil resource at a depth of approximately 12,000 feet. The Red
River is exploited via vertical well bores with minimal completion procedures. Targets are
identified using a proprietary 3-D seismic attribute analysis. Since late 2007, we have drilled
and completed three Red River discoveries in Sheridan County, Montana.
Overview of Williston Basin Acreage Position
Our acreage position in the Williston Basin is comprised of approximately 282,584 net acres.
Approximately 99,215 net acres is east of the Nesson Anticline in Mountrail County, North Dakota
and adjoining counties to the north, south and east. Acreage east of the Nesson Anticline includes
approximately 5,387 net acres in our Parshall / Austin / Sanish project area in Mountrail County where
drilling activities are typically operated by others and we therefore participate in wells in a
non-operated role. Acreage east of the Nesson Anticline also incorporates approximately 36,645 net
acres in our Ross Project area in Mountrail County where we both operate and participate in
non-operated North Dakota wells. Currently, we anticipate drilling 13 operated gross wells (7.4
net) in and around our Mountrail County, North Dakota acreage position in 2010.
Approximately 100,056 net areas is west of the Nesson Anticline in Williams and McKenzie
Counties, North Dakota in our Rough Rider project area. Acreage in our Rough Rider project area is
subject to the Drilling Participation Agreement outlined below. Typically, because of our higher
working interests in spacing units, we operate wells in our Rough Rider area but to a lesser degree
will also participate in wells in a non-operated role. Currently, we anticipate drilling 25
operated gross wells (12.7 net) in our Rough Rider project area in 2010. The remaining 83,313 net
acres is located in eastern Montana in Roosevelt and Sheridan Counties in our Ghost Rider project
area. Activity in Montana has been limited but towards the end of 2009 other operators began
drilling and / or permitting wells in the area. Currently, we
anticipate drilling one operated gross well
(1.0 net) on our Montana acreage in 2010 to test the prospectivity of the Bakken, as well as other
conventional or unconventional producing horizons.
Overview of Rough Rider Drilling Participation Agreement
In late August 2009, we entered into a drilling participation agreement in our Rough Rider
project area in order to accelerate operations and address near term state lease expirations. The
initial group of six wells under the agreement has been drilled. In each of the initial six wells,
we have retained 35% of our original working interest and will back in for 35% of our
counterpartys interest in the combined six well group after combined payout (defined as the point
in time when the cumulative net receipts from the initial wells equals or exceeds all expenditures
for such wells). Our counterparty had the option to participate in an additional nine wells. In
December 2009 our counterparty elected to participate in the next group of four wells and in
January 2010, our counterparty elected to participate in the final group of five wells. We have
elected to retain our maximum interest of 50% of our original working interest in the additional
nine wells. Further, we will have the option to keep up to 64% of our original working interest in
all subsequent in fill development wells in all 15 drilling units.
24
2009 Williston Basin Drilling and Completion Activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FRAC |
|
|
IP |
|
|
30 DAY |
|
WELL NAME |
|
County |
|
OBJECTIVE |
|
~WI |
|
|
STAGES |
|
|
(Boe/d) |
|
|
Average (Boe/d)** |
|
Williston 25-36 #1H |
|
Williams |
|
Bakken |
|
|
33 |
%* |
|
|
32 |
|
|
|
3,394 |
|
|
|
1,505 |
|
Strand 16-9 #1H |
|
Williams |
|
Bakken |
|
|
22 |
%* |
|
|
26 |
|
|
|
2,264 |
|
|
|
948 |
|
Lee 16-21 #1H |
|
Williams |
|
Bakken |
|
|
31 |
%* |
|
|
28 |
|
|
|
1,544 |
|
|
|
698 |
|
BCD Farms 16-21 #1H |
|
Williams |
|
Bakken |
|
|
25 |
%* |
|
|
28 |
|
|
|
1,776 |
|
|
|
702 |
|
Brad Olson 9-16 #1H |
|
Williams |
|
Bakken |
|
|
33 |
%* |
|
|
28 |
|
|
|
2,112 |
|
|
|
811 |
|
Figaro 29-32 #1H |
|
McKenzie |
|
Bakken |
|
|
95 |
% |
|
|
19 |
|
|
|
1,895 |
|
|
|
831 |
|
Anderson 28-33 #1H |
|
Mountrail |
|
Bakken |
|
|
66 |
% |
|
|
24 |
|
|
|
2,154 |
|
|
|
1,346 |
|
Strobeck 27-34 #1H |
|
Mountrail |
|
Three Forks |
|
|
77 |
% |
|
|
18 |
|
|
|
2,021 |
|
|
|
989 |
|
Olson 10-15 #1H |
|
Williams |
|
Bakken |
|
|
100 |
% |
|
|
20 |
|
|
|
1,433 |
|
|
|
730 |
|
|
|
|
|
|
|
Averages |
|
|
2,066 |
|
|
|
951 |
|
|
|
|
* |
|
Rough Rider drilling participation agreement wells where our working interest is anticipated to increase upon payout. |
|
** |
|
Excludes any days well was down for remediation. |
2010 Williston Basin Drilling and Completion Activity / 2010 Capital Budget
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FRAC |
|
|
IP |
|
|
30 DAY |
|
WELL NAME |
|
County |
|
OBJECTIVE |
|
~WI |
|
|
STAGES |
|
|
(Boe/d) |
|
|
Average (Boe/d)** |
|
Liffrig 29-20 #1H |
|
Mountrail |
|
Three Forks |
|
|
72 |
% |
|
|
29 |
|
|
|
2,477 |
|
|
NA |
|
Owan-Nehring 27-34 |
|
Williams |
|
Bakken |
|
|
49 |
% |
|
|
30 |
|
|
|
2,513 |
|
|
NA |
|
Jackson 35-34 #1H |
|
Williams |
|
Bakken |
|
|
62 |
% |
|
|
30 |
|
|
|
3,540 |
|
|
907 |
|
State 36-1 #1H |
|
Williams |
|
Bakken |
|
|
16 |
%* |
|
|
30 |
|
|
|
3,807 |
|
|
1,516 |
|
|
|
|
|
|
|
Averages |
|
|
3,084 |
|
|
1,212 |
|
|
|
|
* |
|
Rough Rider drilling participation agreement wells where our working interest is anticipated to increase upon payout. |
|
** |
|
Excludes any days well was down for remediation. |
During 2010, we anticipate spending approximately $175.8 million to drill and complete 39
gross (21.1 net) operated wells and 4.6 net non-operated wells in the Williston Basin.
Additionally, we anticipate spending approximately $14.2 million on land and seismic. See Item 7.
Managements Discussion and Analysis of Financial Condition and Results of Operations Capital
Commitments Overview of Capital Activity.
Onshore Gulf Coast Province
Our Onshore Gulf Coast province is a high potential, multi-pay province that lends itself to
3-D seismic exploration due to its substantial structural and stratigraphic complexity. We
believe our established 3-D seismic exploration approach, combined with our exploration staffs
extensive experience and accumulated knowledge base in the Onshore Gulf Coast province, provides us
with significant competitive advantages.
Key operating trends within this province include the Vicksburg trend in Brooks County, Texas,
the Miocene and Upper Oligocene trends in Southern Louisiana and the Frio trend in and around
Matagorda County, Texas.
25
During 2009, activity in the onshore Gulf Coast province was significantly reduced due to
depressed natural gas prices and our allocation of capital to the Williston Basin. During the
year, we completed one gross well (0.6 net) in
one attempt for a completion rate of 100%. In 2009, we spent $7.4 million on drilling, land
and seismic in our Onshore Gulf Coast province. Our capital expenditures were allocated 45% to
Southern Louisiana, 32% to the Frio and 15% to the Vicksburg.
For 2010, we currently plan to spend $6.2 million in our Onshore Gulf Coast province.
Approximately $5.3 million of this spending has been allocated to drilling, with the remaining $0.9
million allocated to land and seismic activities. We anticipate that approximately 74% of the
drilling, land and seismic will be allocated to the Vicksburg trend with the remaining 26%
allocated to other areas in the province.
Vicksburg Trend
Our Vicksburg activity is focused principally in Brooks County, Texas, in our Home Run, Triple
Crowne, and Floyd Fields. We discovered these fields in 1999, 2001 and 2002, respectively. Since
1999, we have drilled 43 Vicksburg wells and we have completed 41 of those wells. We believe we
have a multi-year inventory of proved, probable and possible drilling locations in our Home Run,
Triple Crown and Floyd Fields.
In 2009, we spent approximately $1.1 million establishing production from zones that were
classified as proved developed not producing at year end 2008.
In
2010, we anticipate drilling one operated gross (1.0 net) well in the Vicksburg trend in the first
half of 2010 depending upon both favorable natural gas prices and service costs.
Southern Louisiana Trend
In Southern Louisiana, we have utilized our geophysical, geological and operational expertise
to explore for hydrocarbon bearing Miocene and Oligocene reservoirs. These reservoirs are
generally on trend with the Texas Gulf Coast Frio and are therefore logical extensions of our
drilling activities.
In December 2007, we entered into a joint venture to operate
the drilling of at least five prospects over the subsequent 18 months, earning a 50% working
interest. In February 2009, the remaining joint venture well, the Chandeleur Sound SL 19312 #1,
was brought on line at an initial production rate of
approximately 2.9 MMcfe per day. We maintain a 50% working interest in the well. During 2009, we
spent $3.3 million in Southern Louisiana primarily to complete wells in progress at year-end 2008.
In 2010, we have no current plans to drill in Southern Louisiana.
Frio Trend
During
2009, we drilled one operated gross well (0.6 net) in Matagorda County, Texas. The G.S.
Harrison Unit #2 was completed in March 2009 and was production tested at an early rate of 3.0
MMcfe per day from the lowest 20 feet of pay.
|
|
|
In 2010, we have no current plans to drill in the Frio Trend. |
Anadarko Basin Province
The Anadarko Basin is located in the Texas Panhandle and Western Oklahoma. We believe this
prolific natural gas producing province offers a combination of relatively lower risk exploration
and development opportunities in shallower horizons, as well as higher risk, but higher reserve
potential opportunities in the deeper sections that have been relatively under explored.
The stratigraphic and structural objectives in the Anadarko Basin can provide excellent
targets for 3-D seismic imaging. In addition, drilling economics in the Anadarko Basin are
enhanced by the multi-pay nature of many of the prospects, with secondary or tertiary targets
serving as either incremental value or as alternatives if the primary target zone is not
productive. Our recent activity has been focused primarily in the Hunton, Springer Channel,
Springer Bar and Granite Wash trends.
26
In
2009, we received proceeds of $1.4 million related to the sale
of mineral interests. Because of
the sale, we spent a ($1.2) million in the Anadarko Basin during
2009. In 2010, we have no current plans to drill in the Anadarko
Basin.
West Texas and Other Province
The Permian Basin of West Texas and Eastern New Mexico is a predominantly oil producing
province with generally longer life reserves than that of our onshore Gulf Coast. Our drilling
activity in our West Texas province has been focused primarily in various carbonate reservoirs,
including the Canyon Reef and Fusselman formations of the Horseshoe Atoll trend, the Canyon Reef of
the Eastern Shelf, the Wolfcamp and Devonian section 5 of New Mexico, and the Mississippian Reef of
the Hardeman Basin, at depths ranging from 7,000 to 13,000 feet.
During 2009, we completed one gross well in two attempts for a 50% completion rate and spent a
total of $0.7 million on drilling, land and seismic.
We anticipate spending $1.1 million to drill 3 gross (0.4 net) wells in West Texas in 2010.
Title to Properties
We believe we have satisfactory title, in all material respects, to substantially all of our
producing properties in accordance with standards generally accepted in the oil and natural gas
industry. Our properties are subject to royalty interests, standard liens incident to operating
agreements, liens for current taxes and other burdens, which we believe do not materially interfere
with the use of or affect the value of such properties. Substantially all of our proved oil and
natural gas properties are pledged as collateral for borrowings under our Senior Credit Facility.
See Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
- Liquidity and Capital Resources Senior Credit Facility and Item 7. Managements Discussion
and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources 9
5/8% Senior Notes due 2014.
Oil and Natural Gas Reserves
Our estimated total net proved reserves of oil and natural gas as of December 31, 2009 are as
follows:
Summary
of Oil and Gas Reserves as of Fiscal-Year-End Based on Average
Fiscal-Year Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves |
|
|
|
Oil |
|
|
NaturalGas |
|
|
Total |
|
|
|
(MMBbls) |
|
|
(Bcf) |
|
|
(MMBoe)(a) |
|
PROVED |
|
|
|
|
|
|
|
|
|
|
|
|
Developed: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
5.3 |
|
|
|
29.2 |
|
|
|
10.2 |
|
Undeveloped: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
11.3 |
|
|
|
37.2 |
|
|
|
17.5 |
|
|
|
|
|
|
|
|
|
|
|
TOTAL PROVED |
|
|
16.6 |
|
|
|
66.4 |
|
|
|
27.7 |
|
|
|
|
(a) |
|
Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
The preparation of our reserve report is outlined in our Sarbanes Oxley Act Section 404
internal control procedures. Our procedures require that our reserve report is prepared by a registered
independent engineering firm at the end of every year based on information provided by our
Reservoir Engineering Department.
Our Reservoir Engineering Department accumulates historical production data for our wells,
calculates historical lease operating expenses and differentials, updates working interests and net
revenue interests, obtains updated Authorizations for Expenditure from our Operational Engineering
Department and obtains logs, 3-D seismic and other geological and geophysical information from our
Geological and Geophysical Department. This data is forwarded to Cawley, Gillespie & Associates,
Inc. (CGA), our registered independent petroleum consultants.
27
CGA prepares a report of our estimated proved reserves in their entirety based on the
information provided to them. CGA is a Texas Registered Engineering Firm (F-693). Our primary
contact at CGA is Mr. W. Todd Brooker, Vice President. Mr. Brooker is a State of Texas Licensed
Professional Engineer (License #83462). See Exhibit 99.1 Report of Cawley, Gillespie & Associates,
Inc.
In accordance with applicable requirements of the Securities and Exchange Commission (SEC),
estimates of our net proved reserves and future net revenues are made using average prices at the
beginning of each month in the 12-month period prior to the date of such reserve estimates and are
held constant throughout the life of the properties (except to the extent a contract specifically
provides for escalation). Estimated quantities of net proved reserves and future net revenues
therefrom are affected by oil and natural gas prices, which have fluctuated widely in recent
years. See Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations Critical Accounting Policies New Accounting Pronouncements.
There are numerous uncertainties inherent in estimating oil and natural gas reserves and their
estimated values, including many factors beyond our control. The reserve data set forth in the CGA
report represents only estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an exact manner. The
accuracy of any reserve estimate is a function of the quality of available data and of engineering
and geologic interpretation and judgment. As a result, estimates of different engineers, including
those used by us, may vary. In addition, estimates of reserves are subject to revision based upon
actual production, results of future development and exploration activities, prevailing oil and
natural gas prices, operating costs and other factors. The revisions may be material.
Accordingly, reserve estimates are often different from the quantities of oil and natural gas that
are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which
they are based. Our estimated net proved reserves, included in our SEC filings, have not been
filed with or included in reports to any other federal agency. See Item 1A. Risk Factors -
Although our oil and natural gas reserve data is independently estimated, these estimates may still prove
to be inaccurate.
Estimates with respect to net proved reserves that may be developed and produced in the future
are often based upon volumetric calculations and upon analogy to similar types of reserves rather
than actual production history. Estimates based on these methods are generally less reliable than
those based on actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations in the estimated reserves that may be substantial.
Proved Undeveloped Reserves
Our total proved undeveloped (PUD) reserves as of December 31, 2009 were 17.5 MMBoe. PUD
reserves represented 63% of our total proved reserves in 2009 versus 54% in 2008. The increase in
our PUD reserves as a percentage of our total proved reserves was attributable to the application
of advanced drilling and completion techniques, improved oil prices, reduced service costs and the
modernization of SEC reserve reporting rules.
The application of advance drilling and completion techniques, which incorporates drilling
long laterals and completing wells with swell packers and between 18 and 32 fracture stimulation
stages in 2009, appears to have enhanced our estimated ultimate recoveries (EURs) and thereby
improved our rates of return. During 2009, we applied these advanced drilling and completion
techniques to areas that had previously experienced minimal drilling activity and drilled
apparently economic wells. In these areas, we were able to increase our level of PUD reserves.
Oil prices used in our year-end 2009 reserve report increased 37% relative to 2008. During
2009, service costs decreased approximately 40% as the pace of drilling activity in the United
States decreased due to the economic crisis, resulting recession and scarcity of available capital.
Enhanced oil prices and reduced service costs improved our rates of return and allowed us to book
PUD reserves in previously uneconomic locations. Enhanced oil prices also typically lengthens the
time that a well can be economically produced and therefore increases the amount of economically
recoverable reserves over the life of the well.
28
The modernization of SEC oil and gas reporting rules also enhanced our level of PUD reserves.
Effective with years ending on or after December 31, 2009, the SEC modernized its rules with
respect to oil and gas reserves for the first time since 1982. The new rules increased the number
of offsetting PUD locations we were able to book in
unconventional resource plays such as the Williston Basin from two in 2008 to four in 2009.
The increased number of offsetting locations we are able to book allowed us to increase our level
of PUD reserves and, therefore, also increased our level of total proved reserves. Approximately 4.0
MMBoe in reserves were booked at year-end 2009 related to the SEC rules changes.
Partially offsetting the above PUD reserve increases, we eliminated multiple PUD reserve
locations in areas that we currently do not anticipate drilling within the next five years. The
PUD reserve locations that we eliminated were primarily natural gas drilling locations in areas
outside of our core Williston Basin and South Texas acreage positions and totaled 2.9 MMBoe.
Our PUD reserves also decreased due to the drilling of 18 gross PUD wells (2.8 net) during
2009. During the year, we spent approximately $14.3 million dollars converting 0.98 MMBoe from PUD
to proved developed producing reserves.
Reconciliation of Standardized Measure to Pre-tax PV10%
Pre-tax PV10% is the estimated present value of the future net revenues from our proved oil
and natural gas reserves before income taxes discounted using a 10% discount rate. Pre-tax PV10%
is considered a non-GAAP financial measure under SEC regulations because it does not include the
effects of future income taxes, as is required in computing the standardized measure of discounted
future net cash flows. We believe that pre-tax PV10% is an important measure that can be used to
evaluate the relative significance of our oil and natural gas properties and that pre-tax PV10% is
widely used by securities analysts and investors when evaluating oil and natural gas companies.
Because many factors that are unique to each individual company impact the amount of future income
taxes to be paid, the use of a pre-tax measure provides greater comparability of assets when
evaluating companies. We believe that most other companies in the oil and natural gas industry
calculate pre-tax PV10% on the same basis. Pre-tax PV10% is computed on the same basis as the
standardized measure of discounted future net cash flows but without deducting income taxes. The
table below provides a reconciliation of our standardized measure of discounted future net cash
flows to our pre-tax PV10% value (in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Standardized measure of discounted future net cash flows |
|
$ |
246.5 |
|
|
$ |
279.3 |
|
|
$ |
394.5 |
|
Add present value of future income tax discounted at 10% |
|
|
7.6 |
|
|
|
8.7 |
|
|
|
97.1 |
|
|
|
|
|
|
|
|
|
|
|
Pre-tax PV10% |
|
$ |
254.1 |
|
|
$ |
288.0 |
|
|
$ |
491.6 |
|
|
|
|
|
|
|
|
|
|
|
29
Drilling Activities
We drilled, or participated in the drilling of, the following wells during the periods
indicated.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Exploratory wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
0 |
|
|
|
0.0 |
|
|
|
4 |
|
|
|
1.3 |
|
|
|
0 |
|
|
|
0 |
|
Oil |
|
|
1 |
|
|
|
0.1 |
|
|
|
1 |
|
|
|
0.8 |
|
|
|
3 |
|
|
|
1.1 |
|
Non-productive |
|
|
1 |
|
|
|
0.2 |
|
|
|
2 |
|
|
|
1.0 |
|
|
|
7 |
|
|
|
3.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2 |
|
|
|
0.3 |
|
|
|
7 |
|
|
|
3.1 |
|
|
|
10 |
|
|
|
4.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
1 |
|
|
|
0.6 |
|
|
|
9 |
|
|
|
4.5 |
|
|
|
8 |
|
|
|
5.7 |
|
Oil |
|
|
38 |
|
|
|
4.8 |
|
|
|
52 |
|
|
|
7.8 |
|
|
|
11 |
|
|
|
4.2 |
|
Non-productive |
|
|
0 |
|
|
|
0.0 |
|
|
|
0 |
|
|
|
0.0 |
|
|
|
0 |
|
|
|
0.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
39 |
|
|
|
5.4 |
|
|
|
61 |
|
|
|
12.3 |
|
|
|
19 |
|
|
|
9.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Present Activities
As of December 31, 2009, we had four operated rigs in the Williston Basin. Two of
the rigs were drilling locations representing 0.6 net wells. The remaining two
drilling rigs were in the process of moving to their next drilling location. At
year-end, we also had one non-operated well drilling in the
Williston Basin
representing 0.05 net wells. Finally, we had 13 wells in the Williston Basin waiting
on completion representing 2.1 net wells. Three of the wells waiting on completion were operated
locations representing 1.8 net wells.
We do not own drilling rigs and all of our drilling activities have been conducted by
independent contractors or by industry participant operators under standard drilling contracts.
Delivery Commitments
As of December 31, 2009, we had no commitments to provide fixed and determinable quantities of
oil or natural gas in the near future under contracts or agreements.
Productive Wells and Acreage
Productive Wells
The following table sets forth our ownership interest at December 31, 2009 in productive oil
and natural gas wells in the areas indicated. Wells are classified as oil or natural gas according
to their predominant production stream. Gross wells are the total number of producing wells in
which we have an interest, and net wells are determined by multiplying gross wells by our average
working interest.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas |
|
|
Oil |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Rocky Mountains |
|
|
0 |
|
|
|
0 |
|
|
|
115 |
|
|
|
22.9 |
|
|
|
115 |
|
|
|
22.9 |
|
Onshore Gulf Coast |
|
|
60 |
|
|
|
34.1 |
|
|
|
16 |
|
|
|
4.2 |
|
|
|
76 |
|
|
|
38.3 |
|
Anadarko Basin |
|
|
71 |
|
|
|
19.6 |
|
|
|
11 |
|
|
|
1.7 |
|
|
|
82 |
|
|
|
21.3 |
|
West Texas and Other |
|
|
10 |
|
|
|
1.3 |
|
|
|
73 |
|
|
|
23.3 |
|
|
|
83 |
|
|
|
24.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
141 |
|
|
|
55.0 |
|
|
|
215 |
|
|
|
52.1 |
|
|
|
356 |
|
|
|
107.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
Productive wells consist of producing wells and wells capable of production, including wells
waiting on pipeline connection. Wells that are completed in more than one producing horizon are
counted as one well. Of the gross wells reported above, two had multiple completions.
Acreage
Undeveloped acreage includes leased acres on which wells have not been drilled or completed to
a point that would permit the production of commercial quantities of oil and natural gas,
regardless of whether or not such acreage contains proved reserves. The following table sets forth
the approximate developed and undeveloped acreage that we held as leasehold interest at December
31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed(a) |
|
|
Undeveloped(a) |
|
|
Total |
|
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
|
Gross |
|
|
Net |
|
Rocky Mountains |
|
|
55,657 |
|
|
|
31,791 |
|
|
|
499,600 |
|
|
|
297,854 |
|
|
|
555,257 |
|
|
|
329,645 |
|
Onshore Gulf Coast |
|
|
22,385 |
|
|
|
9,558 |
|
|
|
9,387 |
|
|
|
5,430 |
|
|
|
31,772 |
|
|
|
14,988 |
|
Anadarko Basin |
|
|
62,086 |
|
|
|
17,629 |
|
|
|
11,748 |
|
|
|
7,826 |
|
|
|
73,834 |
|
|
|
25,455 |
|
West Texas & Other |
|
|
20,326 |
|
|
|
5,729 |
|
|
|
10,000 |
|
|
|
1,940 |
|
|
|
30,326 |
|
|
|
7,669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
160,454 |
|
|
|
64,707 |
|
|
|
530,735 |
|
|
|
313,050 |
|
|
|
691,189 |
|
|
|
377,757 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Does not include acreage for which assignments have not been received. |
All of our leases for undeveloped acreage summarized in the preceding table will expire at the
end of their respective primary terms unless we renew the existing leases, we establish production
from the acreage, or some other savings clause is exercised. The following table sets forth the
minimum remaining lease terms for our gross and net undeveloped acreage.
|
|
|
|
|
|
|
|
|
|
|
Acres Expiring |
|
Twelve Months Ending: |
|
Gross |
|
|
Net |
|
December 31, 2010 |
|
|
55,071 |
|
|
|
29,151 |
|
December 31, 2011 |
|
|
118,412 |
|
|
|
73,978 |
|
December 31, 2012 |
|
|
138,174 |
|
|
|
89,781 |
|
December 31, 2013 |
|
|
103,532 |
|
|
|
61,500 |
|
December 31, 2014 |
|
|
26,764 |
|
|
|
21,035 |
|
Thereafter |
|
|
88,782 |
|
|
|
37,605 |
|
|
|
|
|
|
|
|
Total |
|
|
530,735 |
|
|
|
313,050 |
|
|
|
|
|
|
|
|
In addition, as of December 31, 2009, we had mineral interests covering approximately 11,488
gross and 1,854 net acres. The mineral acres will continue into perpetuity and will not expire.
31
Sales Volumes, Prices and Production Costs
The following table sets forth our sales volumes, the average prices we received before hedging,
the average prices we received including hedging settlement gains (losses), the average price
including hedging settlements and unrealized gains (losses) and average production costs associated
with our sale of oil and natural gas for the periods indicated. We account for our hedges using
mark-to-market accounting, which requires that we record both derivative settlements and unrealized
gains (losses) to the consolidated statement of operations within a single income statement line
item. We have elected to include both derivative settlements and unrealized gains (losses) within
revenue.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Sales volumes(a): |
|
|
|
|
|
|
|
|
|
|
|
|
Oil volumes (MBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountains |
|
|
610 |
|
|
|
292 |
|
|
|
44 |
|
Onshore Gulf Coast |
|
|
88 |
|
|
|
151 |
|
|
|
200 |
|
Anadarko Basin |
|
|
21 |
|
|
|
24 |
|
|
|
32 |
|
West Texas & Other |
|
|
95 |
|
|
|
111 |
|
|
|
116 |
|
|
|
|
|
|
|
|
|
|
|
Total oil |
|
|
814 |
|
|
|
578 |
|
|
|
392 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas volumes (MMcf) |
|
|
|
|
|
|
|
|
|
|
|
|
Rocky Mountains |
|
|
169 |
|
|
|
53 |
|
|
|
28 |
|
Onshore Gulf Coast |
|
|
4,211 |
|
|
|
6,032 |
|
|
|
9,716 |
|
Anadarko Basin |
|
|
1,441 |
|
|
|
1,821 |
|
|
|
2,766 |
|
West Texas & Other |
|
|
71 |
|
|
|
90 |
|
|
|
116 |
|
|
|
|
|
|
|
|
|
|
|
Total natural gas |
|
|
5,892 |
|
|
|
7,996 |
|
|
|
12,626 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil equivalent (MBoe) |
|
|
1,796 |
|
|
|
1,911 |
|
|
|
2,496 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average oil prices based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil price (per Bbl) |
|
$ |
54.79 |
|
|
$ |
89.06 |
|
|
$ |
72.30 |
|
Oil price including derivative settlement gains (losses) (per Bbl) |
|
$ |
53.99 |
|
|
$ |
84.63 |
|
|
$ |
71.51 |
|
Oil price including derivative settlements and unrealized gains
(losses) (per Bbl) |
|
$ |
48.65 |
|
|
$ |
89.79 |
|
|
$ |
65.57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas prices based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price (per Mcf) |
|
$ |
4.01 |
|
|
$ |
9.21 |
|
|
$ |
7.30 |
|
Natural gas price including derivative settlement gains (losses)
(per Mcf) |
|
$ |
5.71 |
|
|
$ |
9.08 |
|
|
$ |
7.66 |
|
Natural gas price including derivative settlements and unrealized
gains (losses) (per Mcf) |
|
$ |
5.21 |
|
|
$ |
9.48 |
|
|
$ |
7.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average equivalent prices based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil equivalent price (per Boe) |
|
$ |
37.97 |
|
|
$ |
65.50 |
|
|
$ |
48.30 |
|
Oil equivalent price including derivative settlement gains
(losses) (per Boe) |
|
$ |
43.19 |
|
|
$ |
63.62 |
|
|
$ |
49.98 |
|
Oil equivalent price including derivative settlements and
unrealized gains (losses) (per Boe) |
|
$ |
39.12 |
|
|
$ |
66.84 |
|
|
$ |
47.64 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average production costs (per Boe) based on sales volumes: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses (includes costs for operating and
maintenance and expensed workovers) |
|
$ |
7.61 |
|
|
$ |
5.89 |
|
|
$ |
3.66 |
|
Ad valorem taxes |
|
$ |
0.56 |
|
|
$ |
0.58 |
|
|
$ |
0.60 |
|
Production taxes |
|
$ |
2.84 |
|
|
$ |
2.81 |
|
|
$ |
1.02 |
|
|
|
|
(a) |
|
Sales volumes for 2009 exclude 16,475 barrels of oil produced during the year but held in
inventory. Ending inventory at year end 2008 and 2007 was not material. During 2009,
production volumes for crude oil were 830 MBbls and total oil equivalent production volumes
were 1,812 MBoe. |
32
|
|
|
Item 3. |
|
Legal Proceedings |
We are, from time to time, party to certain lawsuits and claims arising in the ordinary course
of business. While the outcome of lawsuits and claims cannot be predicted with certainty,
management does not expect these matters to have a materially adverse effect on our financial
condition, results of operations or cash flows.
As of December 31, 2009, there are no known environmental or other regulatory matters related
to our operations that are reasonably expected to result in a material liability to us. Compliance
with environmental laws and regulations has not had, and is not expected to have, a material
adverse effect on our capital expenditures.
|
|
|
Item 4. |
|
Submission of Matters to a Vote of Security Holders |
|
(a) |
|
We convened a Special Meeting of Stockholders on Wednesday, October 7, 2009, in
Austin, Texas at 9:00 a.m. local time. |
|
|
(b) |
|
N/A |
|
(c) |
|
Out of the total 82,862,476 shares of our common stock outstanding and entitled
to vote, 73,600,146 shares were present in person or by proxy at the special
meeting, representing approximately 89% of our common stock outstanding. The only
matters voted on by our stockholders, as fully described in the definitive proxy
materials for the special meeting, are set forth below. The results were as follows: |
|
1. |
|
To approve an amendment to our Certificate of Incorporation to
increase the number of authorized shares of common stock from 90 million shares
to 180 million shares. |
|
|
|
|
|
For |
|
|
66,363,106 |
|
Against |
|
|
6,976,123 |
|
Abstained |
|
|
260,917 |
|
Broker non-votes |
|
|
0 |
|
|
2. |
|
To approve an amendment to the 1997 Incentive Plan to increase
the number of shares of common stock available under the plan. |
|
|
|
|
|
For |
|
|
40,626,366 |
|
Against |
|
|
10,202,489 |
|
Abstained |
|
|
113,391 |
|
Broker non-votes |
|
|
22,657,900 |
|
33
Executive Officers of the Registrant
Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General Instruction G(3) to
Form 10-K, the following information is included in Part I of this report. The following are our
executive officers as of February 25, 2010.
|
|
|
|
|
|
|
Name |
|
Age |
|
Position |
Ben M. Brigham
|
|
|
50 |
|
|
Chief Executive Officer, President and Chairman |
Eugene B. Shepherd, Jr.
|
|
|
51 |
|
|
Executive Vice President and Chief Financial Officer |
David T. Brigham
|
|
|
49 |
|
|
Executive Vice President Land and Administration
and Director |
A. Lance Langford
|
|
|
47 |
|
|
Executive Vice President Operations |
Jeffery E. Larson
|
|
|
51 |
|
|
Executive Vice President Exploration |
Ben M. Bud Brigham has served as our Chief Executive Officer, President and Chairman of the
Board since we were founded in 1990. From 1984 to 1990, Mr. Brigham served as an exploration
geophysicist with Rosewood Resources, an independent oil and gas exploration and production
company. Mr. Brigham began his career in Houston as a seismic data processing geophysicist for
Western Geophysical, Inc. a provider of 3-D seismic services, after earning his B.S. in Geophysics
from the University of Texas at Austin. Mr. Brigham is the brother of David T. Brigham, Executive
Vice President Land and Administration.
Eugene B. Shepherd, Jr. has served as Executive Vice President and Chief Financial Officer
since October 2003, and previously served as Chief Financial Officer from June 2002 to October
2003. Mr. Shepherd has approximately 26 years of financial and operational experience in the energy
industry. Prior to joining us, Mr. Shepherd served as Integrated Energy Managing Director for the
investment banking division of ABN AMRO Bank, where he executed merger and acquisition advisory,
capital markets and syndicated loan transactions for energy companies. Prior to joining ABN AMRO,
Mr. Shepherd spent fourteen years as an investment banker for Prudential Securities Incorporated,
Stephens Inc. and Merrill Lynch Capital Markets. Mr. Shepherd worked as a petroleum engineer for
over four years for both Amoco Production Company and the Railroad Commission of Texas. He holds a
B.S. in Petroleum Engineering and an MBA, both from the University of Texas at Austin.
David T. Brigham joined us in 1992 and has served as a Director since May 2003 and as
Executive Vice President Land and Administration since June 2002. Mr. Brigham served as Senior
Vice President Land and Administration from March 2001 to June 2002, Vice President Land and
Administration from February 1998 to March 2001, as Vice President Land and Legal from 1994 until
February 1998 and as Corporate Secretary from February 1998 to September 2002. From 1987 to 1992,
Mr. Brigham worked as an attorney in the energy section with Worsham, Forsythe, Sampels &
Wooldridge. For a brief period of time before attending law school, Mr. Brigham was a landman for
Wagner & Brown Oil and Gas Producers, an independent oil and gas exploration and production
company. Mr. Brigham holds a B.B.A. in Petroleum Land Management from the University of Texas and a
J.D. from Texas Tech School of Law. Mr. Brigham is the brother of Ben M. Brigham, Chief Executive
Officer, President and Chairman of the Board.
A. Lance Langford joined us in 1995 as Manager of Operations, served as Vice President -
Operations from January 1997 to March 2001, served as Senior Vice President Operations from March
2001 to September 2003 and has served as Executive Vice President Operations since September
2003. From 1987 to 1995, Mr. Langford served in various engineering capacities with Meridian Oil
Inc., handling a variety of reservoir, production and drilling responsibilities. Mr. Langford holds
a B.S. in Petroleum Engineering from Texas Tech University.
Jeffery E. Larson joined us in 1997 and was Vice President Exploration from August 1999 to
March 2001, Senior Vice President Exploration from March 2001 to September 2003 and has served as
Executive Vice President Exploration since September 2003. Prior to joining us, Mr. Larson was an
explorationist in the Offshore Department of Burlington Resources, a large independent exploration
company, where he was responsible for generating exploration and development drilling
opportunities. Mr. Larson worked at Burlington from 1990 to 1997 in various roles of
responsibility. Prior to Burlington, Mr. Larson spent five years at Exxon as a Production Geologist
and Research Scientist. He holds a B.S. in Earth Science from St. Cloud State University in
Minnesota and a M.S. in Geology from the University of Montana.
34
PART II
|
|
|
Item 5. |
|
Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Price Range of Common Stock, Performance Graph, and Dividend Policy
Our common stock commenced trading on the NASDAQ Global Select Market (formerly the NASDAQ
National Market) on May 8, 1997 under the symbol BEXP. The following table sets forth the high
and low intra-day sales prices per share of our common stock for the periods indicated on the
NASDAQ Global Select Market for the periods indicated. The sales information below reflects
inter-dealer prices, without retail mark-ups, mark-downs or commissions and may not necessarily
represent actual transactions.
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
Low |
|
2008: |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
8.16 |
|
|
$ |
4.86 |
|
Second Quarter |
|
|
18.29 |
|
|
|
5.76 |
|
Third Quarter |
|
|
17.62 |
|
|
|
10.00 |
|
Fourth Quarter |
|
|
10.91 |
|
|
|
2.30 |
|
2009: |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
4.25 |
|
|
$ |
1.04 |
|
Second Quarter |
|
|
4.30 |
|
|
|
1.60 |
|
Third Quarter |
|
|
10.61 |
|
|
|
2.50 |
|
Fourth Quarter |
|
|
14.93 |
|
|
|
7.99 |
|
The
closing market price of our common stock on February 23, 2010 was $15.55 per share.
As of February 23, 2010, there were an estimated 155 record owners of our common stock.
35
The following graph is a comparison of cumulative total returns. It assumes that $100 was
invested in our common stock, the NASDAQ Composite Index, and the S&P Oil & Gas E&P Select Industry
Index at the end of 2004 and remained invested through year-end 2009. The Indexes and the graph
were prepared by an independent third party. The NASDAQ Composite Index is calculated using the
over 3,000 companies which trade on The NASDAQ Stock Market, including both domestic and foreign
companies. The S&P Oil & Gas E&P Select Industry Index (SPSIOP) represents the oil and gas
exploration and production sub-industry portion of the S&P Total Market Index.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN
Among Brigham Exploration Company, The NASDAQ Composite Index
And The S&P Oil & Gas Exploration & Production Index
|
|
|
* |
|
$100 invested on 12/31/04 in stock or index, including reinvestment of dividends.
|
|
|
|
|
|
Fiscal year ending December 31. |
No dividends have been declared or paid on our common stock to date. We intend to retain all
future earnings for the development of our business. Our Senior Credit Facility, Senior Notes, and
Series A preferred stock restrict our ability to pay dividends on our common stock.
We are obligated to pay cash dividends on our Series A preferred stock. See Item 7.
Managements Discussion and Analysis of Financial Condition and Results of Operations Liquidity
and Capital Resources Mandatorily Redeemable Preferred Stock.
36
Securities Authorized for Issuance under Equity Compensation Plans
The following table includes information regarding our equity compensation plans as of the
year ended December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
|
|
|
|
|
|
|
|
|
Securities |
|
|
|
Number of |
|
|
|
|
|
|
Remaining |
|
|
|
Securities to be |
|
|
|
|
|
|
Available for |
|
|
|
Issued upon |
|
|
Weighted- |
|
|
Future Issuance |
|
|
|
Exercise of |
|
|
Average Price of |
|
|
Under Equity |
|
|
|
Outstanding |
|
|
Outstanding |
|
|
Compensation |
|
Plan Category |
|
Options |
|
|
Options |
|
|
Plans |
|
Equity
compensation plans
approved by
security holders(a) |
|
|
4,170,137 |
|
|
$ |
5.14 |
|
|
|
566,800 |
|
Equity compensation
plans not approved
by security holders |
|
|
|
|
|
|
NA |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
4,170,137 |
|
|
$ |
5.14 |
|
|
|
566,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Does not include 556,990 shares of restricted stock issued and outstanding at December 31,
2009. |
Issuer Purchases of Equity Securities
In 2009, we elected to allow employees to deliver shares of vested restricted stock with a
fair market value equal to their federal, state and local tax withholding amounts on the date of
issue in lieu of cash payment.
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
Average Price |
|
Period |
|
Shares Purchased |
|
|
Paid per Share |
|
October 2009 |
|
|
2,597 |
|
|
$ |
9.55 |
|
December 2009 |
|
|
37,433 |
|
|
$ |
13.86 |
|
|
|
|
|
|
|
|
Total |
|
|
40,030 |
|
|
|
13.58 |
|
|
|
|
|
|
|
|
37
|
|
|
Item 6. |
|
Selected Consolidated Financial Data |
This section presents our selected consolidated financial data and should be read in
conjunction with Item 7. Managements Discussion and Analysis of Financial Condition and Results
of Operations and our consolidated financial statements and related notes included in Item 8.
Financial Statements and Supplementary Data. The selected consolidated financial data in this
section is not intended to replace our consolidated financial statements.
38
We derived the statement of operations data and statement of cash flows data for the years
ended December 31, 2009, 2008 and 2007, and balance sheet data as of December 31, 2009 and 2008
from the audited consolidated financial statements included in this report. We derived the
statement of operations data and statement of cash flows data for the years ended December 31, 2006
and 2005 and the balance sheet data as of December 31, 2007, 2006 and 2005, from our accounting
books and records.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands, except per share information) |
|
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
68,192 |
|
|
$ |
125,108 |
|
|
$ |
120,557 |
|
|
$ |
102,835 |
|
|
$ |
96,820 |
|
Gain (loss) on derivatives, net |
|
|
2,064 |
|
|
|
2,548 |
|
|
|
(1,664 |
) |
|
|
3,335 |
|
|
|
|
|
Other revenue |
|
|
88 |
|
|
|
132 |
|
|
|
88 |
|
|
|
127 |
|
|
|
220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
70,344 |
|
|
|
127,788 |
|
|
|
118,981 |
|
|
|
106,297 |
|
|
|
97,040 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
14,655 |
|
|
|
12,363 |
|
|
|
10,704 |
|
|
|
10,701 |
|
|
|
7,161 |
|
Production taxes |
|
|
5,098 |
|
|
|
5,374 |
|
|
|
2,541 |
|
|
|
4,021 |
|
|
|
3,353 |
|
General and administrative |
|
|
9,243 |
|
|
|
9,557 |
|
|
|
9,276 |
|
|
|
7,887 |
|
|
|
5,533 |
|
Depletion of oil and natural gas properties |
|
|
32,054 |
|
|
|
53,498 |
|
|
|
59,079 |
|
|
|
46,386 |
|
|
|
33,268 |
|
Impairment of oil and natural gas properties |
|
|
114,781 |
|
|
|
237,180 |
|
|
|
6,505 |
|
|
|
|
|
|
|
|
|
Depreciation and amortization |
|
|
812 |
|
|
|
629 |
|
|
|
613 |
|
|
|
537 |
|
|
|
762 |
|
Loss on inventory valuation |
|
|
2,196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount on asset retirement
obligations |
|
|
421 |
|
|
|
361 |
|
|
|
379 |
|
|
|
317 |
|
|
|
180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses |
|
|
179,260 |
|
|
|
318,962 |
|
|
|
89,097 |
|
|
|
69,849 |
|
|
|
50,257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(108,916 |
) |
|
|
(191,174 |
) |
|
|
29,884 |
|
|
|
36,448 |
|
|
|
46,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
578 |
|
|
|
191 |
|
|
|
654 |
|
|
|
1,207 |
|
|
|
245 |
|
Interest expense, net |
|
|
(16,431 |
) |
|
|
(14,495 |
) |
|
|
(14,622 |
) |
|
|
(9,688 |
) |
|
|
(3,980 |
) |
Gain loss on derivatives, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,213 |
|
|
|
(814 |
) |
Other income (expense) |
|
|
1,544 |
|
|
|
530 |
|
|
|
1,022 |
|
|
|
1,352 |
|
|
|
238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (expense ) |
|
|
(14,309 |
) |
|
|
(13,774 |
) |
|
|
(12,946 |
) |
|
|
(3,916 |
) |
|
|
(4,311 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes and
cumulative effect of change in accounting
principle |
|
|
(123,225 |
) |
|
|
(204,948 |
) |
|
|
16,938 |
|
|
|
32,532 |
|
|
|
42,472 |
|
Income tax benefit (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
233 |
|
|
|
42,701 |
|
|
|
(6,728 |
) |
|
|
(12,744 |
) |
|
|
(15,037 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
233 |
|
|
|
42,701 |
|
|
|
(6,728 |
) |
|
|
(12,744 |
) |
|
|
(15,037 |
) |
Net income (loss) available to common
stockholders |
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
$ |
10,210 |
|
|
$ |
19,788 |
|
|
$ |
27,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share available to
common shareholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
$ |
0.23 |
|
|
$ |
0.44 |
|
|
$ |
0.65 |
|
Diluted |
|
|
(1.74 |
) |
|
|
(3.57 |
) |
|
|
0.22 |
|
|
|
0.43 |
|
|
|
0.63 |
|
Weighted average shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,110 |
|
|
|
45,017 |
|
|
|
42,481 |
|
Diluted |
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,531 |
|
|
|
45,597 |
|
|
|
43,728 |
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(In thousands) |
|
Statement of Cash Flows Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
51,750 |
|
|
$ |
69,630 |
|
|
$ |
90,449 |
|
|
$ |
88,687 |
|
|
$ |
64,379 |
|
Investing activities |
|
|
(164,620 |
) |
|
|
(179,866 |
) |
|
|
(99,093 |
) |
|
|
(171,747 |
) |
|
|
(113,220 |
) |
Financing activities |
|
|
113,608 |
|
|
|
136,416 |
|
|
|
18,207 |
|
|
|
83,385 |
|
|
|
50,535 |
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
40,781 |
|
|
$ |
40,043 |
|
|
$ |
13,863 |
|
|
$ |
4,300 |
|
|
$ |
3,975 |
|
Oil and natural gas properties,
using the full cost method of
accounting, net |
|
|
330,733 |
|
|
|
404,839 |
|
|
|
510,207 |
|
|
|
485,525 |
|
|
|
347,329 |
|
Total assets |
|
|
498,256 |
|
|
|
489,056 |
|
|
|
548,428 |
|
|
|
522,587 |
|
|
|
380,427 |
|
Long-term debt |
|
|
158,968 |
|
|
|
303,730 |
|
|
|
168,492 |
|
|
|
149,334 |
|
|
|
63,100 |
|
Series A preferred stock,
mandatorily redeemable (a) |
|
|
10,101 |
|
|
|
10,101 |
|
|
|
10,101 |
|
|
|
10,101 |
|
|
|
10,101 |
|
Total stockholders equity |
|
|
264,283 |
|
|
|
121,269 |
|
|
|
279,027 |
|
|
|
266,015 |
|
|
|
241,640 |
|
|
|
|
(a) |
|
At year-end 2009, our Series A preferred stock was classified as a current
liability as it will be redeemed in October 2010. |
|
|
|
Item 7. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations |
Statements in the following discussion may be forward-looking and involve risk and
uncertainty. The following discussion should be read in conjunction with our Consolidated
Financial Statements and Notes hereto.
Sources of Our Revenues
We derive our revenues from the sale of oil and natural gas that is produced from our
properties. Revenues are a function of the production volumes sold and the prevailing market
prices at the time of sale.
To achieve more predictable cash flows and to reduce our exposure to downward price
fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our
oil and natural gas production. Our current strategy is to hedge up to 90% of our proved developed
producing (PDP) volumes for the upcoming 12 months and up to 80% of our PDP volumes for the
remaining period. The use of certain types of derivative instruments may prevent us from realizing
the benefit of upward price movements. See Item 1A. Risk Factors Our hedging activities may
prevent us from benefiting from price increases and may expose us to other risks.
Components of Our Cost Structure
Production Costs are the day-to-day costs we incur to bring hydrocarbons out of the ground and
to the market combined with the daily costs we incur to maintain our producing properties. This
includes lease operating expenses and production taxes.
|
|
|
Lease operating expenses are generally comprised of several components including: the
cost of labor and supervision to operate our wells and related equipment; repairs and
maintenance; fluid treatment and disposal; related materials, supplies, and fuel; and
insurance applicable to our wells and related facilities and equipment. Lease operating
expenses also include the cost for expensed workovers. Lease operating expenses are driven
in part by the type of commodity produced, the level of workover activity and the
geographical location of the properties. Oil is inherently more expensive to produce than
natural gas. |
|
|
|
Lease operating expenses also include ad valorem taxes, which are imposed by local
taxing authorities such as school districts, cities, and counties or boroughs. The amount
of tax we pay is based on a percent of value of the property assessed or determined by the
taxing authority on an annual basis. When oil and natural gas prices rise, the value of
our underlying property interests increase, which results in higher ad valorem taxes. |
40
|
|
|
In the U.S., there are a variety of state and federal taxes levied on the production of
oil and natural gas. These are commonly grouped together and referred to as production
taxes. The majority of our production tax expense is based on a percent of gross value
realized at the wellhead at the time the production is sold or removed from the lease. As
a result, our production tax expense increases when oil and gas prices rise. |
|
|
|
Historically, taxing authorities have occasionally encouraged the oil and natural gas
industry to explore for new oil and natural gas reserves, or to develop high cost reserves,
through reduced tax rates or tax credits. These incentives have been narrow in scope and
short-lived. A small number of our wells have qualified for reduced production taxes
because they were discoveries based on the use of 3-D seismic or they are high cost wells. |
Depreciation, Depletion and Amortization is the systematic expensing of the capital costs
incurred to acquire, explore and develop oil and natural gas. As a full cost company, we
capitalize all direct costs associated with our exploration and development efforts, including a
portion of our interest and certain general and administrative costs, and apportion these costs to
each unit of production sold through depletion expense. Generally, if reserve quantities are
revised up or down, our depletion rate per unit of production will change inversely. When the
depreciable capital cost base increases or decreases, the depletion rate will move in the same
direction.
Asset Retirement Accretion Expense is the systematic, monthly accretion of future abandonment
costs of tangible assets such as wells, service assets, pipelines, and other facilities.
General and Administrative Expense includes payroll and benefits for our corporate staff,
costs of maintaining our headquarters, managing our production and development operations and legal
compliance. We capitalize general and administrative costs directly related to prospect generation
and our exploration activities.
Interest. We rely on our Senior Credit Facility to fund our short-term liquidity (working
capital) and a portion of our long-term financing needs. The interest rate that we pay on our
Senior Credit Facility correlates with both fluctuations in interest rates and the amount
outstanding under the facility. We pay a fixed interest rate on both our Senior Notes and our
preferred stock. We expect to continue to incur interest expense as we continue to grow. We
capitalize interest directly related to our unevaluated properties and certain properties under
development, which are not being amortized.
Income Taxes. We are generally subject to a 35% federal income tax rate. For income tax
purposes, we are allowed deductions for accelerated depreciation, depletion, intangible drilling
costs, and state taxes. Through 2009, all of our federal and state income taxes were deferred.
Capital Commitments
Our primary needs for cash are to fund our capital expenditure program, our working capital
obligations and for the repayment of contractual obligations. In the future, cash will also be
required to fund our capital expenditures for the exploration and development of properties
necessary to offset the inherent declines in production and proven reserves that are typical in an
extractive industry like ours and also to hold acreage that would otherwise expire if not drilled.
Future success in growing reserves and production will be highly dependent on our access to cost
effective capital resources and our success in economically finding and producing additional oil
and natural gas reserves. Funding for our exploration and development of oil and natural gas
activities and the repayment of our contractual obligations may be provided by any combination of
cash flow from operations, cash on our balance sheet, the unused committed borrowing capacity under
our Senior Credit Facility, reimbursements of prior land and seismic costs by third parties who
participate in our projects, and the sale of interests in projects and properties or alternative
financing sources as discussed in - Contractual Obligations and - Liquidity and Capital
Resources. Cash flows from operations and the unused committed borrowing capacity under our
Senior Credit Facility fund our working capital obligations.
41
Overview of Capital Activity
Our improving operational results in the Williston Basin Bakken and Three Forks plays during
2008, largely attributable to increasing the number of fracture stimulation stages in each
horizontal wellbore, led us to increase our capital expenditure budget in the Williston Basin in
2008 and reduce our conventional portfolio activity in the
Onshore Gulf Coast, the Anadarko Basin and West Texas. We added a second Williston Basin
drilling rig during the last half of 2008 to accelerate drilling east of the Nesson Anticline in
Mountrail County, North Dakota as well as to begin development of acreage west of the Nesson
Anticline in Williams and McKenzie Counties, North Dakota.
Unfortunately, as we added our second drilling rig, commodity prices rapidly deteriorated
during the last half of 2008 because of the financial crisis and recession experienced both in the
United States and internationally. Crude oil and natural gas prices, which had peaked at
approximately $145.29 per barrel and $13.58 per Mcf in July 2008, reached a 2008 low of $33.87 per
barrel and $5.29 per Mcf in December 2008. Despite decreasing prices, continued high levels of
drilling activity by operators sustained the elevated drilling and completion costs and overall project returns
were negatively impacted because of the mismatch that existed between commodity prices and the cost
to drill and complete wells.
In early 2009, to combat the reduction in our rates of return and the general deteriorating
availability of capital, we elected to cease drilling and completion operations post completion of
the Olson 10-15 #1H, which was our first long lateral well with 20 fracture stimulation stages. In March 2009, we
announced a 2009 capital budget of $37.1 million, which was largely comprised of costs to complete
the Olson 10-15 #1H and costs related to several other wells that we ceased operations prior to
reaching the completion stage.
In March 2009, crude oil prices began to rebound and prices averaged $48.06 per barrel.
During the first half of 2009, other operators reduced or ceased drilling activity and the number
of rigs operating in the Williston Basin rapidly declined from a peak rate of 93 rigs running in
November 2008 to 31 rigs running in May 2009. As a result of the reduction in drilling rigs at
work in the Williston Basin and elsewhere in the United States, it is estimated that costs to drill
and complete wells in the Williston Basin were reduced 30 to 40% relative to the peak rates seen in
late 2008 and early 2009.
In May 2009, commodity prices continued to improve and crude oil averaged $59.21 per barrel
during the month. Also during this period, economic conditions began to stabilize due to actions
taken by governments around the world and capital markets availability improved. In order to
restart our Williston Basin drilling program, we elected to raise approximately $93.4 million in
net proceeds from the May 2009 equity offering and announced an increase to our 2009 capital budget to $64.5
million.
Shortly thereafter,
we commenced completion operations on the wells that we had deferred
completing in February 2009. In addition, we picked up a rig to begin drilling operations west of the Nesson
Anticline in our Rough Rider project area. In August, we announced entry into a drilling
participation agreement, which allowed us to drill additional locations in Rough Rider subject to
state lease expirations. We were able to maintain a relatively flat capital expenditure profile
for the second half of 2009 even after increasing the number of gross wells drilled, as we reduced
our working interest in wells to 35% of our original working interest as a result of the drilling
participation agreement.
In October 2009, we raised an additional $168.3 million in net proceeds from an equity offering in order to
pre-fund an increased level drilling activity in 2010. Our preliminary 2010 capital budget announced
in October 2009, concurrent with the equity offering, was estimated to be $175.8 million and we estimated that we would drill 24 net
wells in the Williston Basin and two net wells in our South Texas Vicksburg play.
In 2010, we estimate that we will have four rigs running in the Williston Basin and drill 39
gross (21.1 net) operated wells and 4.6 net non-operated wells. Overall, we currently estimate
that we will spend approximately $199.3 million on drilling, land and seismic capital expenditures during 2010. We anticipate
funding our 2010 capital expenditure budget through cash on our balance sheet, which was a result
of our May and October 2009 equity offerings, cash flow from operations, availability under our
Senior Credit Facility, which at year-end 2009 had a borrowing base of $110 million, and through
potential divestiture transactions in our conventional asset portfolio.
42
Capital Expenditures
The timing of most of our capital expenditures is discretionary because we operate the
majority of our wells and we have no material long-term capital expenditure commitments.
Consequently, we have a significant degree of
flexibility to adjust the level of our capital expenditures as circumstances warrant. Our
capital expenditure program includes the following:
|
|
|
cost of acquiring and maintaining our lease acreage position and our seismic resources; |
|
|
|
cost of drilling and completing new oil and natural gas wells; |
|
|
|
cost of installing new production infrastructure; |
|
|
|
cost of maintaining, repairing and enhancing existing oil and natural gas wells; |
|
|
|
cost related to plugging and abandoning unproductive or uneconomic wells; and |
|
|
|
indirect costs related to our exploration activities, including payroll and other
expenses attributable to our exploration professional staff. |
In 2010, as a result of our May and October 2009 equity offerings and improved operational
results, we are increasing our level of activity in the Williston Basin and currently estimate that
we will spend $216.3 million on capital expenditures during
2010, which includes $199.3 million on drilling, land and seismic
capital expenditures and $17.0 million for capitalized costs and other assets.
Factors that could cause us to further increase our level of activity and capital budget in
2010 include a further reduction in service and material costs, the formation of joint ventures
with other exploration and production companies, the divestiture of non-strategic assets, and a
further improvement in commodity prices or well performance that exceeds our risked forecasts, all
of which would positively impact our operating cash flow.
Factors that would cause us to reduce our capital budget in 2010 include, but are not limited
to, increases in service and materials costs, reductions in commodity prices or underperformance of
wells relative to our risked forecasts, all of which would negatively impact our operating cash
flow.
43
Our budgeted capital expenditures for 2010 are as follows:
|
|
|
|
|
|
|
2010 |
|
|
|
(In millions) |
|
Drilling |
|
$ |
183.7 |
|
Net land and seismic |
|
|
15.6 |
|
Capitalized costs |
|
|
14.8 |
|
Other non-oil & gas assets |
|
|
2.2 |
|
|
|
|
|
Total |
|
$ |
216.3 |
|
|
|
|
|
The final determination with respect to our 2010 budgeted expenditures will depend on a number
of factors, including:
|
|
|
production from our existing producing wells; |
|
|
|
the results of our current exploration and development drilling efforts; |
|
|
|
economic conditions at the time of drilling; |
|
|
|
industry conditions at the time of drilling, including the availability of drilling and
completion equipment; |
|
|
|
our liquidity and the availability of external sources of financing; and |
|
|
|
the availability of more economically attractive prospects. |
There can be no assurance that the budgeted wells will, if drilled, encounter commercial
quantities of oil or natural gas.
The capital that funds our drilling activities is allocated to individual prospects based on
the value potential of a prospect, as measured by a risked net present value analysis. We start
each year with a budget and re-evaluate this budget monthly. The primary factors that impact this
value creation measure include forecasted commodity prices, drilling and completion costs, and a
prospects risked reserve size and risked initial producing rate. Other factors that are also
monitored throughout the year that influence the amount and timing of all our planned expenditures
include the level of production from our existing oil and natural gas properties, the availability
of drilling and completion services, and the success and resulting production of our newly drilled
wells. The outcome of our monthly analysis results in a reprioritization of our exploration and
development drilling schedule to ensure that we are optimizing our capital expenditure plan.
To support our prospect generation activities, we allocate a portion of our capital
expenditures to land and seismic. Over the past three years, we have spent $55.1 million on land
and seismic activities.
For a more in depth discussion of our 2009 capital expenditures see Item 2. Properties.
44
Contractual Obligations
The following schedule summarizes our known contractual cash obligations at December 31, 2009
and the effect these obligations are expected to have on our future cash flow and liquidity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Year |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2012- |
|
|
2014 and |
|
|
|
Total |
|
|
2010 |
|
|
2011 |
|
|
2013 |
|
|
Thereafter |
|
|
|
(In thousands) |
|
Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior Notes |
|
$ |
160,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
160,000 |
|
Senior Credit Facility |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mandatorily redeemable, Series A preferred stock |
|
|
10,101 |
|
|
|
10,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
170,101 |
|
|
$ |
10,101 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
160,000 |
|
Other commitments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest, Senior Notes(a) |
|
$ |
69,300 |
|
|
$ |
15,400 |
|
|
$ |
15,400 |
|
|
$ |
30,800 |
|
|
$ |
7,700 |
|
Interest, Senior Credit Facility(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend Mandatorily redeemable, Series A
preferred stock(c) |
|
|
504 |
|
|
|
504 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling rigs(d) |
|
|
800 |
|
|
|
800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cancelable operating leases |
|
|
1,837 |
|
|
|
721 |
|
|
|
738 |
|
|
|
378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
242,542 |
|
|
$ |
27,526 |
|
|
$ |
16,138 |
|
|
$ |
31,178 |
|
|
$ |
167,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Calculated assuming $160 million of Senior Notes outstanding and an interest rate of 9.625%.
The payments are made in May and November until maturity in May 2014. |
|
(b) |
|
Calculated assuming no amounts outstanding under our Senior Credit Facility. In October
2009, we repaid amounts outstanding under our Senior Credit Facility subsequent to our equity
offering. The interest rate under our facility is dependent upon Eurodollar borrowing rates
plus a margin that fluctuates dependent upon the amount outstanding under the facility. The
Eurodollar rate for one month borrowings was 0.32% on December 31, 2009. The amount of
interest that we pay on amounts borrowed under our Senior Credit Facility will fluctuate over
time as borrowings increase or decrease, as the applicable Eurodollar rate increases and
decreases and as the applicable interest rate increases or decreases. See Item 7A.
Quantitative and Qualitative Disclosures About Market Risk Interest Rate Risk. |
|
(c) |
|
Calculated assuming $10.1 million of Series A preferred stock outstanding, a cash dividend of
6% per annum and a maturity of October 31, 2010. |
|
(d) |
|
Early termination fee of $200,000 per rig if terminated during the quarter. Contract is
quarter-to-quarter evergreen through May 31, 2011. |
We also have liabilities of $6.3 million related to asset retirement obligations on our
Consolidated Balance Sheet as of December 31, 2009. Due to the nature of these obligations, we
cannot determine precisely when payments will be made to settle these obligations. See Item 8.
Financial Statements and Supplementary Data Note 7. Asset
Retirement Obligations.
45
Oil and Natural Gas Reserves
Our estimated total net proved reserves of oil and natural gas as of December 31, 2009, 2008
and 2007 were as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Estimated Net Proved Reserves: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
16.6 |
|
|
|
7.1 |
|
|
|
5.6 |
|
Natural gas (Bcf) |
|
|
66.4 |
|
|
|
94.7 |
|
|
|
106.6 |
|
Oil equivalent (MMBoe)(a) |
|
|
27.7 |
|
|
|
22.8 |
|
|
|
23.4 |
|
Proved developed reserves as a percentage of net proved reserves |
|
|
37 |
% |
|
|
46 |
% |
|
|
49 |
% |
|
|
|
(a) |
|
Boe is defined as one barrel of oil equivalent determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
Our estimated total net proved reserves increased 21% from 2008 to 2009. The increase in our
proved reserves was attributable to the application of advanced drilling and completion techniques,
improved oil prices, reduced service costs and the modernization of SEC reserve reporting rules.
The application of advance drilling and completion techniques, which incorporates drilling
long laterals and completing wells with swell packers and between 18 and 32 fracture stimulation
stages in 2009, appears to have enhanced our estimated ultimate recoveries (EURs) and thereby
improved our rates of return. During 2009, we applied these advanced drilling and completion
techniques to areas that had previously experienced minimal drilling activity and drilled
apparently economic wells. In these areas, we were able to increase our level of both proved
developed (PD) and proved undeveloped (PUD) reserves.
Oil prices used in our year-end 2009 reserve report increased 37% relative to 2008. During
2009, service costs decreased approximately 40% as the pace of drilling activity in the United
States decreased due to the economic crisis, resulting recession and scarcity of available capital.
Enhanced oil prices and reduced service costs improved our rates of return and allowed us to book
reserves in previously uneconomic locations. Enhanced oil prices also typically lengthen the time
that a well can be economically produced and therefore increase the amount of economically
recoverable reserves over the life of the well.
The modernization of SEC oil and gas reporting rules also enhanced our level of reserves. The
new rules increased the number of offsetting PUD locations we were able to book in unconventional
resource plays such as the Williston Basin from two in 2008 to four in 2009. The increased number
of offsetting locations we are able to book allowed us to increase our level of PUD reserves and
therefore also increase our level of total proved reserves. As a result of the increase in the
level of our PUD reserves, our overall percentage of PUD reserves to total net proved reserves
increased from 54% in 2008 to 63% in 2009.
Partially offsetting the above PUD reserve increases, we eliminated multiple PUD reserve
locations in areas that we currently do not anticipate drilling within the next five years. The
PUD reserve locations that we eliminated were primarily natural gas drilling locations in areas
outside of our core Williston Basin and South Texas acreage positions and totaled 2.9 MMBoe.
46
Results of Operations
Comparison of the twelve-month periods ended December 31, 2009, 2008 and 2007
Production volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
Oil (MBbls)(a) |
|
|
830 |
|
|
|
44 |
% |
|
|
578 |
|
|
|
47 |
% |
|
|
392 |
|
Natural gas (MMcf) |
|
|
5,892 |
|
|
|
(26 |
%) |
|
|
7,996 |
|
|
|
(37 |
%) |
|
|
12,626 |
|
Total (MBoe)(b) |
|
|
1,812 |
|
|
|
(5 |
%) |
|
|
1,910 |
|
|
|
(23 |
%) |
|
|
2,496 |
|
Average daily production volumes (Boe/d)(c) |
|
|
5,034 |
|
|
|
(5 |
%) |
|
|
5,306 |
|
|
|
(23 |
%) |
|
|
6,933 |
|
|
|
|
(a) |
|
Includes approximately 16,475 barrels of oil produced in the Williston Basin during 2009 and
recorded as inventory at year-end 2009. Ending inventory at year end 2008 and 2007 was not
material. |
|
(b) |
|
Boe is defined as one barrel equivalent of oil, determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
|
(c) |
|
Average daily production volumes calculated based on 360 day year. |
Inventory
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
Oil (Bbls) |
|
|
16,475 |
|
|
|
NM |
|
|
|
|
|
|
|
NM |
|
|
|
|
|
Natural gas (Mcf) |
|
|
|
|
|
|
NM |
|
|
|
|
|
|
|
NM |
|
|
|
|
|
Total (Boe) |
|
|
16,475 |
|
|
|
NM |
|
|
|
|
|
|
|
NM |
|
|
|
|
|
Sales
volumes (Production volumes less Inventory)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
Oil (MBbls)(a) |
|
|
814 |
|
|
|
41 |
% |
|
|
578 |
|
|
|
47 |
% |
|
|
392 |
|
Natural gas (MMcf) |
|
|
5,892 |
|
|
|
(26 |
%) |
|
|
7,996 |
|
|
|
(37 |
%) |
|
|
12,626 |
|
Total (MBoe)(b) |
|
|
1,796 |
|
|
|
(6 |
%) |
|
|
1,910 |
|
|
|
(23 |
%) |
|
|
2,496 |
|
Average daily sales volumes (Boe/d)(c) |
|
|
4,988 |
|
|
|
(6 |
%) |
|
|
5,306 |
|
|
|
(23 |
%) |
|
|
6,933 |
|
|
|
|
(a) |
|
Excludes approximately 16,475 barrels of oil produced in the Williston Basin during 2009 and
recorded as inventory at year-end 2009. Ending inventory at year end 2008 and 2007 was not
material. |
|
(b) |
|
Boe is defined as one barrel equivalent of oil, determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids. |
|
(c) |
|
Average daily sales volumes calculated based on 360 day year. |
Our
net equivalent sales volumes for 2009 decreased by 6% to 1,796 MBoe (4,988 Boe/d) from
1,910 MBoe (5,306 Boe/d) in 2008. Our sales volumes for 2009 decreased primarily due to our
reduction in activity in the onshore Gulf Coast and the Anadarko Basin in response to low natural
gas prices. This decrease was partially offset by a 116% increase in our sales volumes in the
Williston Basin. Oil represented 45% and 30% of our total production in 2009 and 2008,
respectively. The increase in our oil sales volumes was due to our increased activity in the
Williston Basin, which is primarily a crude oil basin.
The following is additional information regarding our 2009 sales volumes:
|
|
|
Sales volumes from our Rocky Mountains province for 2009
increased 112% when compared to
2008. The increase was attributable to the rapid escalation of our drilling activities in
the Williston Basin, where we completed 38 gross (4.8 net) wells during 2009. Sales volumes
from this province represented 35% of our total sales volumes in 2009 versus 15% in 2008.
Approximately 96% of our 2009 sales volumes from this province were oil compared to 97% in
2008. |
|
|
|
Sales volumes from our Onshore Gulf Coast province for 2009 decreased 32% when compared
to 2008. The decrease in volumes was attributable to the reduction in our drilling
activity in this province in order to
focus our activities in the Williston Basin. Because of our limited drilling program, only
limited new volumes were brought on line to offset the natural decline of our wells. Sales
volumes from this province represented 44% of our total sales volumes in 2009 versus 61% in
2008. Approximately 89% of our 2009 sales volumes from this province were natural gas
compared to 87% in 2008. |
47
|
|
|
Sales volumes from our Anadarko Basin province for 2009 decreased 20% when compared to
2008. The decrease in volumes was attributable to the reduction in drilling activity in
this province in order to focus our activities in the Williston Basin. Because of the
reduction in our drilling program in this province, no new volumes were brought on line to
offset the natural decline of our wells. Sales volumes from this province represented 15%
of our volumes in 2009 versus 17% in 2008. Approximately 92% of our 2009 sales volumes
from this province were natural gas compared to 93% in 2008. |
|
|
|
Sales volumes from our West Texas & Other province for 2009 decreased 15% when compared
to 2008. The decrease in volumes was attributable to the reduction in our drilling
activity in this province in order to focus our activities in the Williston Basin. Because
of our limited drilling program, only limited new volumes were brought on line to offset
the natural decline of our wells. Sales volumes from this province represented 6% of our
total volumes in 2009 versus 7% in 2008. Approximately 89% of our 2009 sales volumes from
this province were oil compared to 88% in 2008. |
Our net equivalent sales volumes for 2008 decreased by 23% to 1,910 MBoe (5,306 Boe/d) from
2,496 MBoe (6,933 Boe/d) in 2007. Our sales volumes for 2008 decreased primarily due to the
natural decline of production from our wells in the Vicksburg and Southern Louisiana.
Additionally, sales volumes decreased as a result of our reallocation of capital expenditures from
our conventional portfolio to the Williston Basin. Our Williston Basin wells are longer life
production wells and do not have the initial production impact that our shorter reserve life
conventional portfolio has on our production. Oil represented 30% and 16% of our total sales
volumes in 2008 and 2007, respectively.
The following is additional information regarding our 2008 sales volumes.
|
|
|
Sales volumes from our Rocky Mountains province for 2008 increased 513% when compared to
2007. The increase was attributable to the rapid escalation of our drilling activities in
the Williston Basin, where we drilled 56 gross (11 net wells) during 2008. Sales volumes
from this province represented 15% of our total volumes in 2008 versus 2% in 2007.
Approximately 97% of our 2008 sales volumes from this province were oil compared to 90% in
2007. |
|
|
|
Sales volumes from our Onshore Gulf Coast province for 2008 decreased 36% when compared
to 2007. The decrease in volumes was attributable to the lower activity levels in the
Vicksburg where we drilled five wells in 2007 versus three wells in 2008. The decrease was
also attributable to the natural decline in our Southern Louisiana wells. Despite drilling
three successful wells in Southern Louisiana in 2008, we did not hook up to production the
first of these wells until December 2008. Our attempts to hook up these wells were
negatively impacted by both Hurricanes Gustav and Ike, which impacted the Southern
Louisiana area and affected the service providers that we utilize to hook up our wells.
Sales volumes from this province represented 61% of our total volumes in 2008 versus 73% in
2007. Approximately 87% of our 2008 sales volumes from this province were natural gas
compared to 89% in 2007. |
|
|
|
Sales volumes from our Anadarko Basin province for 2008 decreased 33% when compared to
2007. The decrease in our volumes was due to the natural decline in our wells and a lower
activity level as we completed three wells in the province during 2007 versus only two in
2008. Sales volumes from this province represented 17% of our total sales volumes in 2008
versus 20% in 2007. Approximately 93% of our 2008 sales volumes from this province were
natural gas compared to 94% in 2007. |
|
|
|
Sales volumes from our West Texas & Other province for 2008 decreased 7% when compared
to 2007. The decrease in volumes was attributable to natural well production declines.
Sales volumes from this province represented 7% of our total sales volumes in 2008 versus
6% in 2007. Approximately 88% of our 2008 sales volumes from this province were oil
compared to 86% in 2007. |
48
Revenue, commodity prices and hedging
The following table shows our revenue from the sale of oil and natural gas for 2009, 2008 and
2007. Our commodity hedges are accounted for using mark-to-market accounting, which requires us to
record both derivative settlements and unrealized derivative gains (losses) to the consolidated
statement of operations within a single income statement line item. We include both derivative
settlements and unrealized derivative gains (losses) within revenue.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
|
|
|
|
|
|
(In thousands, except per unit measurements) |
|
|
|
|
Oil revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue |
|
$ |
44,580 |
|
|
|
(13 |
%) |
|
$ |
51,449 |
|
|
|
81 |
% |
|
$ |
28,347 |
|
Oil derivative settlement gains
(losses) |
|
|
(654 |
) |
|
|
(74 |
%) |
|
|
(2,564 |
) |
|
|
724 |
% |
|
|
(311 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue including oil derivative settlements |
|
$ |
43,926 |
|
|
|
(10 |
%) |
|
$ |
48,885 |
|
|
|
74 |
% |
|
$ |
28,036 |
|
Oil derivative unrealized gains
(losses) |
|
|
(4,343 |
) |
|
|
NM |
|
|
|
2,983 |
|
|
|
NM |
|
|
|
(2,328 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil revenue including derivative settlements and unrealized gains (losses) |
|
|
39,583 |
|
|
|
(24 |
%) |
|
|
51,868 |
|
|
|
102 |
% |
|
|
25,708 |
|
Natural gas revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue |
|
$ |
23,612 |
|
|
|
(68 |
%) |
|
$ |
73,659 |
|
|
|
(20 |
%) |
|
$ |
92,210 |
|
Natural gas derivative settlement gains (losses) |
|
|
10,031 |
|
|
|
NM |
|
|
|
(1,028 |
) |
|
|
NM |
|
|
|
4,478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue including derivative settlements |
|
$ |
33,643 |
|
|
|
(54 |
%) |
|
$ |
72,631 |
|
|
|
(25 |
%) |
|
$ |
96,688 |
|
Natural gas derivative unrealized gains (losses) |
|
|
(2,970 |
) |
|
|
NM |
|
|
|
3,157 |
|
|
|
NM |
|
|
|
(3,503 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas revenue including derivative settlements and unrealized gains (losses) |
|
|
30,673 |
|
|
|
(60 |
%) |
|
|
75,788 |
|
|
|
(19 |
%) |
|
|
93,185 |
|
Oil and natural gas revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenue |
|
$ |
68,192 |
|
|
|
(45 |
%) |
|
$ |
125,108 |
|
|
|
4 |
% |
|
$ |
120,557 |
|
Oil and natural gas derivative settlement gains (losses) |
|
|
9,377 |
|
|
|
NM |
|
|
|
(3,592 |
) |
|
|
NM |
|
|
|
4,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenue including derivative settlement gains (losses) |
|
|
77,569 |
|
|
|
(36 |
%) |
|
|
121,516 |
|
|
|
(3 |
%) |
|
|
124,724 |
|
Oil and natural gas derivative unrealized gains (losses) |
|
|
(7,313 |
) |
|
|
NM |
|
|
|
6,140 |
|
|
|
NM |
|
|
|
(5,831 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas revenue including derivative settlements and unrealized gains (losses) |
|
|
70,256 |
|
|
|
(45 |
%) |
|
|
127,656 |
|
|
|
7 |
% |
|
|
118,893 |
|
Other revenue |
|
|
88 |
|
|
|
(33 |
%) |
|
|
132 |
|
|
|
50 |
% |
|
|
88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue |
|
$ |
70,344 |
|
|
|
(45 |
%) |
|
$ |
127,788 |
|
|
|
7 |
% |
|
$ |
118,981 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average oil prices (based on sales volumes): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil price (per Bbl) |
|
$ |
54.79 |
|
|
|
(38 |
%) |
|
$ |
89.06 |
|
|
|
23 |
% |
|
$ |
72.30 |
|
Oil price including derivative settlement gains (losses) (per Bbl) |
|
$ |
53.99 |
|
|
|
(36 |
%) |
|
$ |
84.63 |
|
|
|
18 |
% |
|
$ |
71.51 |
|
Oil price including derivative settlements and unrealized gains (losses) (per Bbl) |
|
$ |
48.65 |
|
|
|
(46 |
%) |
|
$ |
89.79 |
|
|
|
37 |
% |
|
$ |
65.57 |
|
Average natural gas prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price (per Mcf) |
|
$ |
4.01 |
|
|
|
(56 |
%) |
|
$ |
9.21 |
|
|
|
26 |
% |
|
$ |
7.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas price including derivative settlement gains (losses) (per Mcf) |
|
$ |
5.71 |
|
|
|
(37 |
%) |
|
$ |
9.08 |
|
|
|
19 |
% |
|
$ |
7.66 |
|
Natural gas price including derivative settlements and unrealized gains (losses) (per Mcf) |
|
$ |
5.21 |
|
|
|
(45 |
%) |
|
$ |
9.48 |
|
|
|
28 |
% |
|
$ |
7.38 |
|
Average oil equivalent prices (based on sales volumes): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil equivalent price (per Bbl) |
|
$ |
37.97 |
|
|
|
(42 |
%) |
|
$ |
65.46 |
|
|
|
36 |
% |
|
$ |
48.30 |
|
Oil equivalent price including derivative settlement gains (losses) (per bbl) |
|
$ |
43.19 |
|
|
|
(32 |
%) |
|
$ |
63.60 |
|
|
|
27 |
% |
|
$ |
49.98 |
|
Oil equivalent price including derivative settlements and unrealized gains (losses) (per Bbl) |
|
$ |
39.12 |
|
|
|
(41 |
%) |
|
$ |
66.84 |
|
|
|
40 |
% |
|
$ |
47.64 |
|
49
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
2007 |
|
|
|
to 2009 |
|
|
to 2008 |
|
Change in revenue from the sale of oil |
|
|
|
|
|
|
|
|
Price variance impact |
|
$ |
(27,885 |
) |
|
$ |
9,684 |
|
Sales volume variance impact |
|
|
21,016 |
|
|
|
13,418 |
|
Cash settlement of derivative hedging contracts |
|
|
1,910 |
|
|
|
(2,253 |
) |
Unrealized gains (losses) due to derivative hedging contracts |
|
|
(7,326 |
) |
|
|
5,311 |
|
|
|
|
|
|
|
|
Total change |
|
$ |
(12,285 |
) |
|
$ |
26,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in revenue from the sale of natural gas |
|
|
|
|
|
|
|
|
Price variance impact |
|
$ |
(30,657 |
) |
|
$ |
15,286 |
|
Sales volume variance impact |
|
|
(19,390 |
) |
|
|
(33,837 |
) |
Cash settlement of derivative hedging contracts |
|
|
11,059 |
|
|
|
(5,506 |
) |
Unrealized gains (losses) due to derivative hedging contracts |
|
|
(6,127 |
) |
|
|
6,660 |
|
|
|
|
|
|
|
|
Total change |
|
$ |
(45,115 |
) |
|
$ |
(17,397 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in revenue from the sale of oil and natural gas |
|
|
|
|
|
|
|
|
Price variance impact |
|
$ |
(58,542 |
) |
|
$ |
24,970 |
|
Volume variance impact |
|
|
1,626 |
|
|
|
(20,419 |
) |
Cash settlement of derivative hedging contracts |
|
|
12,969 |
|
|
|
(7,759 |
) |
Unrealized gains (losses) due to derivative hedging contracts |
|
|
(13,453 |
) |
|
|
11,971 |
|
|
|
|
|
|
|
|
Total change |
|
$ |
(57,400 |
) |
|
$ |
8,763 |
|
|
|
|
|
|
|
|
Our 2009 oil and natural gas revenue including derivative settlements and unrealized gains
(losses) decreased $57.4 million, or 45% when compared to 2008. The following were the primary
reasons for the decrease in our revenue:
|
|
|
A 42% decrease in the average oil equivalent price decreased revenue by $58.5 million; |
|
|
|
A $7.3 million unrealized loss due to derivative hedging contracts in 2009 versus a $6.1
million unrealized gain due to derivative hedging contracts in 2008 decreased revenue by
$13.5 million; |
|
|
|
An 41% increase in our oil sales volumes, which was partially offset by a 26% decrease
in our natural gas sales volumes, increased revenue by $1.6 million; and |
|
|
|
A $9.4 million gain from the settlement of derivative contracts in 2009 versus a $3.6
million settlement loss in 2008 increased revenue by $13.0 million. |
Our 2008 oil and natural gas revenue including derivative settlements and unrealized gains
(losses) increased $8.8 million, or 7% when compared to 2007. The following were the primary
reasons for the increase in our revenue:
|
|
|
A 36% increase in the average oil equivalent price increased revenue by $25.0 million; |
|
|
|
A $6.1 million unrealized gain due to derivative hedging contracts in 2008 versus a $5.8
million unrealized loss due to derivative hedging contracts in 2007 increased revenue by
$12.0 million; |
|
|
|
A 23% decrease in our sales volumes decreased revenue by $20.4 million; and |
|
|
|
|
A $3.6 million loss from the settlement of derivative contracts in 2008 versus a $4.2
million settlement gain in 2007 decreased revenue by $7.8 million. |
50
Other revenue. Other revenue relates to fees that we charge third parties who use our gas
gathering systems to move their production from the wellhead to third party gas pipeline systems.
Other revenue for 2009 was $88,000 compared to $132,000 in 2008 and $88,000 in 2007. Costs related
to our gas gathering systems are recorded in lease operating expenses.
Hedging. We utilize swaps, collars, and three way costless collars to (i) reduce the effect
of price volatility on the commodities that we produce and sell, (ii) reduce commodity price risk
and (iii) provide a base level of cash flow in order to assure we can execute at least a portion of
our capital spending plans. See Item 7A. Quantitative and Qualitative Disclosures About Market
Risk Derivative Instruments and Hedging Activities for a description of our derivative contracts
and our open derivative contracts.
The following table details derivative contracts that settled during 2009, 2008 and 2007 and
includes the type of derivative contract, the volume, the weighted average NYMEX reference price
for those volumes, and the associated gain /(loss) upon settlement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
Oil collars and three way costless collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (Bbls) |
|
|
251,000 |
|
|
|
38 |
% |
|
|
182,500 |
|
|
|
(31 |
%) |
|
|
263,000 |
|
Average floor price (per Bbl) |
|
$ |
59.43 |
|
|
|
(15 |
%) |
|
$ |
69.55 |
|
|
|
22 |
% |
|
$ |
56.82 |
|
Average ceiling price (per Bbl) |
|
$ |
80.12 |
|
|
|
(15 |
%) |
|
$ |
93.82 |
|
|
|
15 |
% |
|
$ |
81.50 |
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
902 |
|
|
|
NM |
|
|
$ |
(2,564 |
) |
|
|
724 |
% |
|
$ |
(311 |
) |
Oil swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (Bbls) |
|
|
90,000 |
|
|
|
NM |
|
|
|
|
|
|
|
NM |
|
|
|
|
|
Average swap price (per Bbl) |
|
$ |
50.75 |
|
|
|
NM |
|
|
$ |
|
|
|
|
NM |
|
|
$ |
|
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
(1,556 |
) |
|
|
NM |
|
|
$ |
|
|
|
|
NM |
|
|
$ |
|
|
Total oil gain / (loss) upon settlement
(in thousands) |
|
$ |
(654 |
) |
|
|
(75 |
%) |
|
$ |
(2,564 |
) |
|
|
724 |
% |
|
$ |
(311 |
) |
Natural gas collars and three way
costless collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu) |
|
|
1,960,000 |
|
|
|
(60 |
%) |
|
|
4,850,000 |
|
|
|
(35 |
%) |
|
|
7,425,000 |
|
Average floor price (per MMbtu) |
|
$ |
7.19 |
|
|
|
(6 |
%) |
|
$ |
7.65 |
|
|
|
4 |
% |
|
$ |
7.34 |
|
Average ceiling price (per MMbtu) |
|
$ |
8.83 |
|
|
|
(18 |
%) |
|
$ |
10.75 |
|
|
|
(13 |
%) |
|
$ |
12.40 |
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
8,133 |
|
|
|
NM |
|
|
$ |
(1,028 |
) |
|
|
NM |
|
|
$ |
4,478 |
|
Natural gas swaps |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volumes (MMbtu) |
|
|
2,490,000 |
|
|
|
NM |
|
|
|
|
|
|
|
NM |
|
|
|
|
|
Average swap price (per MMbtu) |
|
$ |
4.359 |
|
|
|
NM |
|
|
$ |
|
|
|
|
NM |
|
|
$ |
|
|
Gain /(loss) upon settlement
(in thousands) |
|
$ |
1,898 |
|
|
|
NM |
|
|
$ |
|
|
|
|
NM |
|
|
$ |
|
|
Total natural gas gain /(loss) upon
settlement (in thousands) |
|
$ |
10,031 |
|
|
|
NM |
|
|
$ |
(1,028 |
) |
|
|
NM |
|
|
$ |
4,478 |
|
51
Operating costs and expenses
Production costs. We believe that per unit of production measures are the most effective
basis for evaluating our production costs. We use this information to internally evaluate our
performance, as well as to evaluate our performance relative to our peers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-of-Production |
|
|
|
(Per Boe based on Sales Volumes) |
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
Production costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance |
|
$ |
6.02 |
|
|
|
22 |
% |
|
$ |
4.92 |
|
|
|
52 |
% |
|
$ |
3.24 |
|
Expensed workovers |
|
|
1.58 |
|
|
|
65 |
% |
|
|
0.96 |
|
|
|
129 |
% |
|
|
0.42 |
|
Ad valorem taxes |
|
|
0.56 |
|
|
|
(7 |
%) |
|
|
0.60 |
|
|
|
0 |
% |
|
|
0.60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
8.16 |
|
|
|
26 |
% |
|
$ |
6.48 |
|
|
|
52 |
% |
|
$ |
4.26 |
|
Production taxes |
|
|
2.84 |
|
|
|
1 |
% |
|
|
2.82 |
|
|
|
176 |
% |
|
|
1.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
$ |
11.00 |
|
|
|
18 |
% |
|
$ |
9.30 |
|
|
|
76 |
% |
|
$ |
5.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount |
|
|
|
(In thousands) |
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
Production costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating & maintenance |
|
$ |
10,823 |
|
|
|
15 |
% |
|
$ |
9,399 |
|
|
|
15 |
% |
|
$ |
8,153 |
|
Expensed workovers |
|
|
2,832 |
|
|
|
53 |
% |
|
|
1,851 |
|
|
|
69 |
% |
|
|
1,097 |
|
Ad valorem taxes |
|
|
1,000 |
|
|
|
(10 |
%) |
|
|
1,113 |
|
|
|
(23 |
%) |
|
|
1,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
14,655 |
|
|
|
19 |
% |
|
$ |
12,363 |
|
|
|
15 |
% |
|
$ |
10,704 |
|
Production taxes |
|
|
5,098 |
|
|
|
(5 |
%) |
|
|
5,374 |
|
|
|
111 |
% |
|
|
2,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
|
$ |
19,753 |
|
|
|
11 |
% |
|
$ |
17,737 |
|
|
|
34 |
% |
|
$ |
13,245 |
|
For 2009, our per unit production cost increased 18% when compared to 2008. The following
were the primary reasons for the increase in our 2009 per unit production costs relative to 2008:
|
|
|
O&M expenses increased 22%, or by $1.10 per Boe, due to increases in salt water
disposal, compressor rental and overhead fees; and |
|
|
|
Expensed workovers increased 65%, or by $0.62 per Boe, due to an increase in the number
and cost of our workovers in 2009, in particular two workovers
associated with our conventional natural gas wells. |
For 2008, our per unit production cost increased 76% when compared to 2007. The following
were the primary reasons for the increase in our 2008 per unit production costs relative to 2007:
|
|
|
O&M expenses increased 52%, or by $1.68 per Boe, due to increases in salt water
disposal, compressor rental and fuel costs; |
|
|
|
Production taxes increased 176%, or by $1.80 per Boe, due to a $2.7 million decrease in
gas production tax abatements in 2008 as compared to 2007; and |
|
|
|
Expensed workovers increased 129%, or by $0.54 per Boe, due to an increase in the number
and cost of our workovers in 2008. |
52
General and administrative expenses. We capitalize a portion of our general and
administrative costs. Capitalized costs include the cost of technical employees who work directly
on our prospect generation and exploration activities and a portion of our associated technical
organization costs such as supervision, telephone and postage.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
|
|
(In thousands, except per unit measurements which are based on sales volumes) |
|
General and administrative costs |
|
$ |
16,961 |
|
|
|
(3 |
%) |
|
$ |
17,551 |
|
|
|
1 |
% |
|
$ |
17,442 |
|
Capitalized general and administrative costs |
|
|
(7,718 |
) |
|
|
(4 |
%) |
|
|
(7,994 |
) |
|
|
(2 |
%) |
|
|
(8,166 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative
Expenses |
|
$ |
9,243 |
|
|
|
(3 |
%) |
|
$ |
9,557 |
|
|
|
3 |
% |
|
$ |
9,276 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses (per Boe) |
|
$ |
5.15 |
|
|
|
3 |
% |
|
$ |
4.98 |
|
|
|
34 |
% |
|
$ |
3.72 |
|
Our general and administrative expenses in 2009 decreased $0.3 million from those in
2008. Before capitalization, our general and administrative costs decreased by $0.6 million. We
experienced the following fluctuations in general and administrative costs:
|
|
|
Total compensation expense decreased by $0.3 million from 2008 to 2009 due to lower
levels of employee salaries and bonuses associated with our cost cutting measures implemented in April
2009; and |
|
|
|
Office expenses decreased by $0.3 million from 2008 to 2009 due to our cost containment
measures. |
Our general and administrative expenses in 2008 increased $0.3 million over those in 2007.
Before capitalization, our general and administrative costs increased by $0.1 million. We
experienced the following fluctuations in general and administrative costs:
|
|
|
Total compensation expense decreased by $0.8 million from 2007 to 2008 due to lower
levels of employee bonuses; and |
|
|
|
Contract and professional fees increased by $0.6 million from 2007 to 2008 due to higher
legal and audit fees. |
Depletion of oil and natural gas properties. Our full-cost depletion expense is driven by
many factors including certain costs spent in the exploration for and development of oil and gas
reserves, production levels, and estimates of proved reserve quantities and future developmental
costs at the end of the year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
|
|
(In thousands, except per unit measurements which are based on sales volumes) |
|
Depletion of oil
and natural gas
properties |
|
$ |
32,054 |
|
|
|
(40 |
%) |
|
$ |
53,498 |
|
|
|
(9 |
%) |
|
$ |
59,079 |
|
Depletion of oil
and natural gas
properties (per
Boe) |
|
$ |
17.85 |
|
|
|
(36 |
%) |
|
$ |
28.02 |
|
|
|
19 |
% |
|
$ |
23.64 |
|
Our depletion expense for 2009 was $21.4 million lower than 2008. A decrease in production
volumes in 2009 lowered depletion expense by approximately $3.2 million, while a decrease in our
depletion rate decreased depletion expense $18.2 million. The lower depletion rate was due to our
fourth quarter 2008 and first quarter 2009 ceiling test writedowns.
Our depletion expense for 2008 was $5.6 million lower than 2007. A decrease in production
volumes in 2008 lowered depletion expense by approximately $13.9 million, while an increase in our
depletion rate increased depletion expense $8.3 million. The higher depletion rate was due to an
increase in finding and development costs in 2008.
Impairment of oil and natural gas properties. We use the full cost method of accounting for
oil and gas properties. Under this method, all acquisition, exploration and development costs,
including certain payroll, asset retirement costs, other internal costs, and interest incurred for
the purpose of finding oil and natural gas reserves, are capitalized. Internal costs and interest
capitalized are directly attributable to acquisition, exploration and development activities and do
not include costs related to production, general corporate overhead or similar activities.
53
Capitalized costs of oil and natural gas properties, net of accumulated amortization, are
limited to the present value (10% per annum discount rate) of estimated future net cash flow from
proved oil and natural gas reserves,
based on the average of oil and natural gas prices in effect at the beginning of each month in
the twelve month period prior to the end of the reporting period; plus the cost of properties not
being amortized, if any; plus the lower of cost or estimated fair value of unproved properties
included in the costs being amortized, if any; less related income tax effects. If net capitalized
costs of oil and gas properties exceed this ceiling amount, we are subject to a ceiling test
writedown to the extent of such excess. A ceiling test writedown is a non-cash charge to earnings
and reduces stockholders equity in the period of occurrence.
The risk that we will experience a ceiling test writedown increases when oil and gas prices
are depressed or if we have a substantial downward revisions in our estimated proved reserves.
Prior to December 31, 2009, the ceiling test calculation was based on oil and natural gas prices in
effect on the balance sheet date. Based on oil and gas prices in effect on March 31, 2009 ($3.63
per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for
differentials), the unamortized cost of our oil and gas properties exceeded the ceiling limit and
we recorded a $114.8 million impairment to our oil and gas properties. Based on oil and gas prices
in effect on December 31, 2008 ($5.71 per MMBtu for Henry Hub gas and $44.60 per barrel for West
Texas Intermediate oil, adjusted for differentials), the unamortized cost of our oil and gas
properties exceeded the ceiling limit and we recorded a $237.2 million impairment to our oil and
gas properties.
Inventory Valuation. Our $2.2 million inventory valuation loss in 2009 was attributable to
the lower of cost or market writedown of oil country tubular goods (OCTG). Market prices of OCTG
experienced a substantial reduction in the first quarter of 2009 associated with lower steel costs
and the oversupply of OCTG due to reduced drilling activity in the United States.
Net interest expense. Interest on our Senior Notes, our Senior Credit Facility and dividends
that we pay on our Series A mandatorily redeemable preferred stock represents the largest portion
of our interest expense. Other costs include commitment fees that we pay on the unused portion of
the borrowing base for our Senior Credit Facility. In addition, we typically pay loan and debt
issuance costs when we enter into new lending agreements or amend existing agreements. When
incurred, these costs are recorded as non-current assets and are then amortized over the life of
the loan. We capitalize interest costs on borrowings associated with our major capital projects
prior to their completion. Capitalized interest is added to the cost of the underlying assets and
is amortized over the lives of the assets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
|
|
(In thousands) |
|
Interest on Senior Notes |
|
$ |
15,400 |
|
|
|
0 |
% |
|
$ |
15,401 |
|
|
|
6 |
% |
|
$ |
14,483 |
|
Interest on Senior Credit Facility |
|
|
3,375 |
|
|
|
72 |
% |
|
|
1,960 |
|
|
|
3 |
% |
|
|
1,900 |
|
Commitment fees |
|
|
195 |
|
|
|
(24 |
%) |
|
|
256 |
|
|
|
54 |
% |
|
|
166 |
|
Dividend on mandatorily
redeemable preferred stock |
|
|
606 |
|
|
|
0 |
% |
|
|
608 |
|
|
|
0 |
% |
|
|
606 |
|
Amortization of deferred loan and
debt issuance cost |
|
|
1,538 |
|
|
|
49 |
% |
|
|
1,032 |
|
|
|
11 |
% |
|
|
932 |
|
Other general interest expense |
|
|
30 |
|
|
|
NM |
|
|
|
|
|
|
|
(100 |
%) |
|
|
2 |
|
Capitalized interest expense |
|
|
(4,713 |
) |
|
|
(1 |
%) |
|
|
(4,762 |
) |
|
|
37 |
% |
|
|
(3,467 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net interest expense |
|
$ |
16,431 |
|
|
|
13 |
% |
|
$ |
14,495 |
|
|
|
(1 |
)% |
|
$ |
14,622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average debt outstanding |
|
$ |
274,211 |
|
|
|
25 |
% |
|
$ |
220,116 |
|
|
|
16 |
% |
|
$ |
189,080 |
|
Average interest rate on
outstanding indebtedness(a) |
|
|
7.15 |
% |
|
|
|
|
|
|
8.28 |
% |
|
|
|
|
|
|
9.1 |
% |
|
|
|
(a) |
|
Calculated as the sum of the interest on our outstanding indebtedness,
commitment fees that we pay on our unused borrowing capacity and the
dividend on our mandatorily redeemable preferred stock divided by the
weighted average debt and preferred stock outstanding for the period. |
54
Our net interest expense for 2009 was $1.9 million higher than that in 2008 primarily due to a
$1.4 million increase in interest expense associated with higher levels of outstanding debt on our
Senior Credit Facility and a $0.5 million increase in origination fees also associated with our
Senior Credit Facility.
Our net interest expense for 2008 was 1% lower than that in 2007. The primary driver behind
the decrease in our net interest expense was an increase in our capitalized interest associated
with our higher level of capital spending in 2008 relative to that in 2007. Interest expense on
our Senior Credit Facility increased by only 3% despite an increase in our weighted average debt
outstanding due to lower interest rates associated with the economic downturn experienced during
the second half of 2008.
Other income (expense). Other income (expense) included:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
|
|
(In thousands) |
|
Other: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on sale of inventory or assets |
|
|
405 |
|
|
|
NM |
|
|
|
|
|
|
|
(100 |
%) |
|
|
71 |
|
Other income (loss) |
|
|
1,139 |
|
|
|
115 |
% |
|
|
530 |
|
|
|
(44 |
%) |
|
|
951 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income (loss) |
|
$ |
1,544 |
|
|
|
191 |
% |
|
$ |
530 |
|
|
|
(48 |
%) |
|
$ |
1,022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income increased in 2009 due to rental income earned on drilling pipe.
Income taxes. We utilize the asset and liability approach to measure deferred tax assets and
liabilities based on temporary differences existing at each balance sheet date using currently
enacted tax rates in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 740 Income Taxes (FASB ASC 740).
Under FASB ASC 740, deferred tax assets are reduced
by a valuation allowance when, in the opinion of management, it is more likely than not that some
portion or all of the deferred tax assets will not be realized. Deferred tax assets and
liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
In 2009, we recognized a current year net deferred
tax benefit of $233,000. The
$233,000 tax benefit was mainly due to miscellaneous state tax benefits. The primary reasons for the difference between our effective tax rate of 0.2% and the
federal statutory rate of 35% were increases in our valuation allowances on federal and state net
operating losses and our inability to deduct dividends and certain portions of our non-cash stock
compensation expense for federal tax purposes.
In 2008, we recognized a current year net deferred federal tax benefit of $40.8 million. The
$40.8 million tax benefit was due to a $222 million decrease in pre-tax income, which primarily
resulted from the ceiling test writedown of $237.2 million. We also recognized a current year net
deferred state tax benefit of $2 million, which consisted of the Margin Tax and other state tax
benefits. The primary reasons for the difference between our effective tax rate of 20.8% and the
federal statutory rate of 35% were increases in our valuation allowances on federal and state net
operating losses and our inability to deduct dividends and certain portions of our non-cash stock
compensation expense for federal tax purposes.
In 2007, we recognized a current year net deferred federal tax liability of $5.5 million,
which consisted of a $5.9 million increase in our 2007 deferred federal income tax expense and a
$0.4 million tax effect of unrealized hedging gains. The $5.9 million increase in our 2007
deferred federal tax expense was primarily due to a $15.6 million decrease in pre-tax income. We
also recognized a current year net deferred state tax liability of $0.9 million, which consisted of
the Margin Tax and other state taxes. The primary reasons for the difference between our effective
tax rate of 39.7% and the federal statutory rate of 35% were due to state income taxes in Texas,
North Dakota, and Louisiana and our inability to deduct dividends and certain portions of our
non-cash stock compensation expense for federal tax purposes.
55
Liquidity and Capital Resources
Sources of Capital
In 2010, we intend to fund our capital expenditure program and contractual commitments with
cash on hand, cash flows from operations, borrowings under our Senior Credit Facility,
reimbursements of prior land and seismic costs by third parties who participate in our projects,
the sale of interests in projects and properties or alternative financing sources.
9 5/8% Senior Notes due 2014
In April 2006, we issued $125 million of Senior Notes. The Senior Notes were priced at
98.629% of their face value to yield 9.875% and are fully and unconditionally guaranteed by us, and
our wholly-owned subsidiaries, Brigham, Inc. and Brigham Oil & Gas, L.P. (the Guarantors). We
entered into an indenture (the Indenture) dated April 20, 2006, among us, the Guarantors and
Wells Fargo Bank, N.A., as trustee, relating to the Senior Notes.
In April 2007, we issued $35 million in Senior Notes. The Senior Notes were issued as an
add-on to our existing $125 million of Senior Notes under the Indenture. The add-on notes were
priced at 99.50% of face value to yield 9.721%.
We are obligated to pay $160 million in cash upon maturity of the Senior Notes in May 2014.
Beginning November 2006, we paid 9 5/8% interest on the $125 million outstanding. Since May 2007,
we have paid interest on the $160 million outstanding. Future interest payments are due
semi-annually in arrears in May and November of each year.
The Senior Notes are unsecured senior obligations, and:
|
|
|
rank equally in right of payment with all our existing and future senior indebtedness; |
|
|
|
rank senior to all of our future subordinated indebtedness; and |
|
|
|
are effectively junior in right of payment to all of our and the Guarantors existing
and future secured indebtedness, including debt of our Senior Credit Facility. |
The Indenture contains customary events of default. Upon the occurrence of certain events of
default, the trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to
be due and payable immediately.
Additionally, the Indenture contains customary restrictions and covenants, which could
potentially limit our flexibility to manage and fund our business. We were in compliance with all
covenants associated with the Senior Notes as of December 31, 2009.
Senior Credit Facility
Our Senior Credit Facility provides for revolving credit borrowings up to $200 million. In
May 2009, in conjunction with our regularly scheduled semi-annual redetermination and our common
stock offering, the borrowing base was reset to $110 million. On July 24, 2009, our Senior Credit
Facility was amended to extend the maturity date from June 2010 to July 24, 2012. Subsequent to
completion of our October 2009 equity offering, we repaid the entire $110.0 million balance
outstanding under our Senior Credit Facility and both at year-end and as of the date of the filing
of this report had and / or have no amounts outstanding.
Covenants under our Senior Notes preclude us from incurring additional debt under the Senior
Credit Facility to the extent our total debt under the Senior Credit Facility exceeds the greater of $50 million plus 15% of a
calculated proved PV10 value based on SEC prices used in our year-end reserve report, as defined in
our Indenture, which is referred to as Adjusted Consolidated Net Tangible Assets, plus, in certain circumstances, an additional 10% of Adjusted Consolidated Net Tangible Assets.
56
Since the borrowing base for our Senior Credit Facility is redetermined at least
semi-annually, the amount of borrowing capacity available to us under our Senior Credit Facility
could fluctuate. In the event that the borrowing
base is adjusted below the amount that we have borrowed, our access to further borrowings will
be reduced, and we may not have the resources necessary to pay off the borrowing base deficiency
and carry out our planned spending for exploration and development activities. See Item 1A Risk
Factors Availability under our Senior Credit Facility is based on a borrowing base which is
subject to redetermination by our lenders. If our borrowing base is reduced, we may be required to
repay amounts outstanding under our Senior Credit Facility.
Borrowings under our Senior Credit Facility bear interest, at our election, at a base rate or
a Eurodollar rate, plus in each case an applicable margin. These margins are reset quarterly and
are subject to increase if the total amount borrowed under our Senior Credit Facility reaches
certain percentages of the available borrowing base, as shown below:
|
|
|
|
|
|
|
|
|
Percent of |
|
Eurodollar |
|
|
|
|
Borrowing Base |
|
Rate |
|
|
Base Rate |
|
Utilized |
|
Advances |
|
|
Advances(1) |
|
< 25% |
|
|
2.50 |
% |
|
|
1.50 |
% |
25% and < 50% |
|
|
2.75 |
% |
|
|
1.75 |
% |
50% and < 75% |
|
|
3.00 |
% |
|
|
2.00 |
% |
75% and < 90% |
|
|
3.25 |
% |
|
|
2.25 |
% |
≥ 90% |
|
|
3.50 |
% |
|
|
2.50 |
% |
|
|
|
(1) |
|
Base rate is defined as for any day a fluctuating rate per annum equal to the highest of the
following, in each case, to the extent determinable by the Administrative Agent: (a) the
Federal Funds Rate plus 1/2 of 1%, (b) the Eurodollar Rate with respect to Interest Periods of
one month determined as of approximately 11:00 a.m. (London time) on such day plus 1.50% and
(c) the rate of interest in effect for such day as publicly announced from time to time by
Bank of America as its prime rate. The prime rate is a rate set by Bank of America based
upon various factors including Bank of Americas costs and desired return, general economic
conditions and other factors, and is used as a reference point for pricing some loans, which
may be priced at, above, or below such announced rate. Any change in such rate announced by
Bank of America shall take effect at the opening of business on the day specified in the
public announcement of such change. |
We are also required to pay a quarterly commitment fee on the average daily unused portion of
the borrowing base. The commitment fees we pay are reset quarterly and are subject to change as
the percentage of the available borrowing base that we utilize changes. The margins and commitment
fees that we pay are as follows:
|
|
|
|
|
Percent of |
|
|
|
Borrowing Base |
|
Annual |
|
Utilized |
|
Commitment Fee |
|
< 25% |
|
|
0.500 |
% |
25% and < 50% |
|
|
0.500 |
% |
50% and < 75% |
|
|
0.500 |
% |
75% and < 90% |
|
|
0.500 |
% |
≥
90% |
|
|
0.500 |
% |
Our Senior Credit Facility also contains customary restrictions and covenants. Should we be
unable to comply with these or other covenants, our senior lenders may be unwilling to waive
compliance or amend the covenants and our liquidity may be adversely affected. Pursuant to our
Senior Credit Facility, our current ratio must be at least 1.0 to 1. Our current ratio was 4.1 to
1 as of December 31, 2009. Pursuant to our Senior Credit Facility, our interest coverage ratio for
the four most recent quarters as of December 31, 2009 and March 31, 2010 must be at least 2.0 to 1,
and thereafter must be at least 2.5 to 1. Our interest coverage ratio for the last twelve-month
period ended December 31, 2009 was 3.2 to 1. The Senior Credit Facility also requires us to
maintain a net leverage ratio for the quarters ending through September 30, 2010 not greater than
4.5 to 1, for the quarters ending December 31, 2010 through March 31, 2011 not greater than 4.25 to 1,
and thereafter not greater than 4.0 to 1. Our net leverage ratio as of December 31, 2009 was 0.7
to 1. Finally, our Senior Credit Facility requires that we maintain $10.0 million in
liquidity in the form of either unused capacity under our Senior Credit Facility or cash
maintained in a deposit account through the date our Mandatorily Redeemable Preferred Stock is
redeemed. As of December 31, 2009, we maintained at least $10.0 million in unused capacity under
our Senior Credit Facility. As of December 31, 2009, we were in compliance with all covenant
requirements in connection with our Senior Credit Facility.
57
Mandatorily Redeemable Preferred Stock
As of December 31, 2009, we had $10.1 million in mandatorily redeemable Series A preferred
stock outstanding, which is held by DLJ Merchant Banking Partners III, L.P. and affiliated funds,
which are managed by affiliates of Credit Suisse Securities (USA), LLC. We are required to satisfy
all dividend obligations related to our Series A preferred stock in cash at a rate of 6% per annum
until it matures in October 2010 or until it is redeemed. Our Series A preferred stock is
redeemable at our option at 100% or 101% of the stated value per share (depending upon certain
conditions) at anytime prior to maturity. We anticipate funding the maturity of our preferred
stock with either cash on hand or borrowings under our Senior Credit Facility.
Access to Capital Markets
On October 5, 2009, our universal shelf registration statement covering the sale of $300
million of our common stock, preferred stock, depositary shares, warrants, rights, units and debt
securities, or any combination of these securities became effective. Following our October 2009
equity offering and the exercise by the underwriters of a portion of their over-allotment in
November 2009, we have approximately $123 million remaining under the shelf registration statement.
This shelf registration statement expires in October 2012. Our ability to raise additional
capital using our shelf registration statement may be limited due to overall conditions of the
stock market or the oil and natural gas industry.
Off Balance Sheet Arrangements
We currently have operating leases, which are considered off balance sheet arrangements. We
do not currently have any other off balance sheet arrangements or other such unrecorded
obligations, and we have not guaranteed the debt of any other party.
Analysis of Changes In Cash and Cash Equivalents
The table below summarizes our sources and uses of cash during 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
|
|
(In thousands) |
|
Net income |
|
$ |
(122,992 |
) |
|
|
24 |
% |
|
$ |
(162,247 |
) |
|
|
NM |
|
|
$ |
10,210 |
|
Non-cash charges |
|
|
159,132 |
|
|
|
(35 |
%) |
|
|
245,545 |
|
|
|
199 |
% |
|
|
82,004 |
|
Changes in working capital and other
items |
|
|
15,610 |
|
|
|
NM |
|
|
|
(13,668 |
) |
|
|
674 |
% |
|
|
(1,765 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows provided by operating
activities |
|
$ |
51,750 |
|
|
|
(26 |
%) |
|
$ |
69,630 |
|
|
|
(23 |
%) |
|
$ |
90,449 |
|
Cash flows used by investing activities |
|
|
(164,620 |
) |
|
|
(8 |
%) |
|
|
(179,866 |
) |
|
|
82 |
% |
|
|
(99,093 |
) |
Cash flows provided (used) by
financing activities |
|
|
113,608 |
|
|
|
(17 |
%) |
|
|
136,416 |
|
|
|
649 |
% |
|
|
18,207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and
cash equivalents |
|
$ |
738 |
|
|
|
(97 |
%) |
|
$ |
26,180 |
|
|
|
174 |
% |
|
$ |
9,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Analysis of net cash provided by operating activities
Net
cash provided by operating activities for 2009 was $17.9 million lower than 2008. The
following are the primary reasons for the decrease:
|
|
|
A 42% decrease in sales prices of crude oil and natural gas decreased operating cash
flow by $58.5 million. |
|
|
|
Higher lease operating costs decreased operating cash flow by $2.3 million. |
58
|
|
|
The change in working capital increased operating cash flow
by $29.3 million. |
|
|
|
Higher realized hedge settlements increased operating cash flow by $13.0 million. |
|
|
|
Higher crude oil volumes partially offset by lower natural gas volumes decreased revenue
by $1.6 million. |
Net
cash provided by operating activities for 2008 was $20.8 million lower than 2007. The
following are the primary reasons for the decrease:
|
|
|
A 23% decrease in production volumes decreased operating cash flow by $20.4 million. |
|
|
|
Lower levels of hedge settlements decreased operating cash flow by $7.8 million. |
|
|
|
Higher lease operating costs, production taxes and general & administrative expense
decreased operating cash flow by $4.8 million. |
|
|
|
The change in working capital reduced operating cash flow by
$11.9 million. |
|
|
|
These decreases in operating cash flow were partially offset by a 36% increase in
prices, which increased operating cash flow by $25.0 million. |
Working Capital
Working capital is the amount by which current assets exceed current liabilities. Typically,
we report a working capital deficit at the end of a period. However, at the end of 2009, as a
result of our May and October 2009 equity offerings we had both cash on hand and short term
investments recorded on our balance sheet. This resulted in a working capital surplus at the end
of 2009. At year-end 2008, we also had a working capital surplus as we had fully drawn our credit
facility and placed the associated cash on deposit. Our 2007 working capital deficit was the
result of accounts payable related to lease operating expenses, exploration and development costs,
royalties payable and gas imbalances payable. Settlement of these payables is typically funded by
cash flows from operations or, if necessary, by additional borrowing under our Senior Credit
Facility.
Our working capital surplus at December 31, 2009 and December 31, 2008 was $90.7 million and
$30.3 million, respectively, while we had a working capital deficit of $9.2 million at December 31,
2007. Our working capital surplus at December 31, 2009, included a current asset of $80.1 million
related to short term investments.
Analysis of changes in cash flows used by investing activities
Net
cash used by investing activities decreased by $15.2 million from 2008 to 2009. The
primary drivers for the decrease were a $78.0 million decrease in our drilling capital expenditures
and a $34.0 million decrease in our land and seismic capital expenditures. These decreases were
offset by a $80.1 million increase in cash used associated with our increased level of short term
investments and a $9.2 million increase in cash used associated with the change in our accrued
drilling costs.
Net
cash used by investing activities increased by $80.8 million from 2007 to 2008. The
primary drivers for the increase were a $39.4 million increase in our drilling capital expenditures
and a $18.3 million increase in our land and seismic capital expenditures. Additionally, in 2008
we received $36 million less in proceeds from asset sales. These increases to cash used in
investing activities were offset by a $13.4 million decrease in cash used in investing activities
associated with the change in our accrued drilling costs.
59
The following is a detailed breakout of our net cash used in investing activities for 2009,
2008 and 2007 in thousands.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
% Change |
|
|
2008 |
|
|
% Change |
|
|
2007 |
|
Capital expenditures for oil and
natural gas activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling |
|
$ |
58,209 |
|
|
|
(57 |
%) |
|
$ |
136,248 |
|
|
|
41 |
% |
|
$ |
96,833 |
|
Land and seismic |
|
|
1,761 |
|
|
|
(95 |
%) |
|
|
35,796 |
|
|
|
104 |
% |
|
|
17,527 |
|
Capitalized cost |
|
|
12,432 |
|
|
|
(3 |
%) |
|
|
12,852 |
|
|
|
10 |
% |
|
|
11,631 |
|
Capitalized asset retirement obligation |
|
|
327 |
|
|
|
(21 |
%) |
|
|
412 |
|
|
|
27 |
% |
|
|
325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
72,729 |
|
|
|
(61 |
%) |
|
$ |
185,308 |
|
|
|
47 |
% |
|
$ |
126,316 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciling Items: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granite Wash proceeds & ARO reduction |
|
$ |
|
|
|
|
NM |
|
|
$ |
|
|
|
|
100 |
% |
|
$ |
(36,050 |
) |
Short term investments |
|
|
80,093 |
|
|
|
NM |
|
|
|
|
|
|
|
NM |
|
|
|
|
|
Other property and equipment |
|
|
1,642 |
|
|
|
249 |
% |
|
|
470 |
|
|
|
24 |
% |
|
|
378 |
|
Change in accrued drilling costs |
|
|
4,270 |
|
|
|
NM |
|
|
|
(4,927 |
) |
|
|
NM |
|
|
|
8,469 |
|
Change in inventory |
|
|
7,881 |
|
|
|
NM |
|
|
|
|
|
|
|
NM |
|
|
|
|
|
Other |
|
|
(1,995 |
) |
|
|
103 |
% |
|
|
(985 |
) |
|
|
4825 |
% |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Reconciling Items |
|
|
91,891 |
|
|
|
NM |
|
|
|
(5,442 |
) |
|
|
(80 |
%) |
|
|
(27,223 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
$ |
164,620 |
|
|
|
(8 |
%) |
|
$ |
179,866 |
|
|
|
82 |
% |
|
$ |
99,093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Analysis of changes in cash flows from financing activities
Over the three year period ended December 31, 2009, we have entered into various financing
transactions with the intent of increasing our liquidity so that we could fund our capital
expenditures for the exploration and development of oil and natural gas properties.
Our net cash provided by financing activities in 2009 was $22.8 million lower than in 2008.
In 2009, we raised $261.7 million in net proceeds from the sale of common stock and repaid the
$145.0 million outstanding under our Senior Credit Facility thereby generating net cash provided by
financing activities of $113.6 million. In 2008, we generated $135 million in financing proceeds
via borrowings under our Senior Credit Facility.
Net cash provided by financing activities in 2008 was $118.2 million higher than that in 2007.
The majority of the increase was due to increased borrowings under our Senior Credit Facility.
Common Stock Transactions
Our net proceeds from the sale of common stock and employee stock option exercises were $260.9
million higher in 2009 than they were in 2008 due to our May and October 2009 equity offerings.
This compares to net proceeds that were $1.6 million higher in 2008 than in 2007.
The following is a list of common stock transactions that occurred in 2009, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Shares Issued |
|
|
Net Proceeds |
|
|
|
|
|
|
(in thousands) |
|
2009 common stock transactions: |
|
|
|
|
|
|
|
|
May 2009 common stock offering |
|
|
36,292,117 |
|
|
$ |
93,407 |
|
October 2009 common stock offering |
|
|
16,837,523 |
|
|
$ |
168,318 |
|
Exercise of employee stock options |
|
|
256,314 |
|
|
$ |
1,219 |
|
2008 common stock transactions: |
|
|
|
|
|
|
|
|
Exercise of employee stock options |
|
|
385,715 |
|
|
$ |
2,066 |
|
2007 common stock transactions: |
|
|
|
|
|
|
|
|
Exercise of employee stock options |
|
|
123,500 |
|
|
$ |
472 |
|
60
Critical Accounting Policies
The establishment and consistent application of accounting policies is a vital component of
accurately and fairly presenting our consolidated financial statements in accordance with generally
accepted accounting principles (GAAP), as well as ensuring compliance with applicable laws and
regulations governing financial reporting. While there are rarely alternative methods or rules
from which to select in establishing accounting and financial reporting policies, proper
application often involves significant judgment regarding a given set of facts and circumstances
and a complex series of decisions.
Use of Estimates
The preparation of financial statements in accordance with GAAP in the United States of
America requires us to make estimates and assumptions that affect our reported assets, liabilities,
revenues, expenses, and some narrative disclosures. Our estimates of our proved oil and natural
gas reserves, future development costs, production expense, revenue and deferred income taxes are
the most critical to our financial statements.
Oil and Natural Gas Reserves
The determination of depreciation, depletion and amortization expense as well as impairments
that are recognized on our oil and natural gas properties are highly dependent on the estimates of
the proved oil and natural gas reserves attributable to our properties. Our estimate of proved
reserves is based on the quantities of oil and natural gas which geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs
under existing economic and operating conditions. The accuracy of any reserve estimate is a
function of the quality of available data, engineering and geological interpretation, and judgment.
For example, we must estimate the amount and timing of future operating costs, severance taxes and
development costs, all of which may in fact vary considerably from actual results. In addition, as
the prices of oil and natural gas and cost levels change from year to year, the economics of
producing our reserves may change and therefore the estimate of proved reserves may also change.
Any significant variance in these assumptions could materially affect the estimated quantity and
value of our reserves.
The information regarding present value of the future net cash flows attributable to our
proved oil and natural gas reserves are estimates only and should not be construed as the current
market value of the estimated oil and natural gas reserves attributable to our properties. Thus,
such information includes revisions of certain reserve estimates attributable to our properties
included in the prior years estimates. These revisions reflect additional information from
subsequent activities, production history of the properties involved and any adjustments in the
projected economic life of such properties resulting from changes in oil and natural gas prices.
Any future downward revisions could adversely affect our financial condition, our borrowing
ability, our future prospects and the value of our common stock.
The estimates of our proved oil and natural gas reserves used in the preparation of our
consolidated financial statements were prepared by Cawley, Gillespie & Associates, Inc., our
registered independent petroleum consultants, and were prepared in accordance with the rules
promulgated by the SEC.
Oil and Natural Gas Property
The method of accounting we use to account for our oil and natural gas investments determines
what costs are capitalized and how these costs are ultimately matched with revenues and expensed.
We utilize the full cost method of accounting to account for our oil and natural gas
investments instead of the successful efforts method because we believe it more accurately reflects
the underlying economics of our programs to explore and develop oil and natural gas reserves. The
full cost method embraces the concept that dry holes and other expenditures that fail to add
reserves are intrinsic to the oil and natural gas exploration business. Thus, under the full cost
method, all costs incurred in connection with the acquisition, development and exploration of oil
and natural gas reserves are capitalized. These capitalized amounts include the costs of unproved
properties, internal costs directly related to acquisitions, development and exploration
activities, asset retirement costs, geological and geophysical costs and capitalized interest.
Although some of these costs will ultimately result in no additional
reserves, they are part of a program from which we expect the benefits of successful wells to
more than offset the costs of any unsuccessful ones. The full cost method differs from the
successful efforts method of accounting for oil and natural gas investments. The primary
difference between these two methods is the treatment of exploratory dry hole costs. These costs
are generally expensed under the successful efforts method when it is determined that measurable
reserves do not exist. Geological and geophysical costs are also expensed under the successful
efforts method. Under the full cost method, both dry hole costs and geological and geophysical
costs are initially capitalized and classified as unevaluated properties pending determination of
proved reserves. If no proved reserves are discovered, these costs are then amortized with all the
costs in the full cost pool.
61
Capitalized amounts except unevaluated costs are depleted using the units of production
method. The depletion expense per unit of production is the ratio of the sum of our unamortized
historical costs and estimated future development costs to our proved reserve volumes. Estimation
of hydrocarbon reserves relies on professional judgment and use of factors that cannot be precisely
determined. Subsequent reserve estimates materially different from those reported would change the
depletion expense recognized during the future reporting periods. For the quarter ended December
31, 2009, our average depletion expense per unit of production was $18.54 per Boe. A 10% decrease
in our estimated net proved reserves at December 31, 2009 would result in a $2.03 per Boe increase
in our per unit depletion expense and a $0.9 million decrease in our pre-tax net income.
To the extent the capitalized costs in our full cost pool (net of depreciation, depletion and
amortization and related deferred taxes) exceed the sum of the present value (using a 10% discount
rate and based on period-end oil and natural gas prices) of the estimated future net cash flows
from our proved oil and natural gas reserves and the capitalized cost associated with our unproved
properties, we would have a capitalized ceiling impairment. Such costs would be charged to
operations as a reduction of the carrying value of oil and natural gas properties. The risk that
we will be required to write down the carrying value of our oil and natural gas properties
increases when oil and natural gas prices are depressed, even if the low prices are temporary. In
addition, capitalized ceiling impairment charges may occur if we experience poor drilling results
or estimations of our proved reserves are substantially reduced. A capitalized ceiling impairment
is a reduction in earnings that does not impact cash flows, but does impact operating income and
stockholders equity. Once recognized, a capitalized ceiling impairment charge to oil and natural
gas properties cannot be reversed at a later date. The risk that we will experience a ceiling test
writedown increases when oil and gas prices are depressed or if we have substantial downward
revisions in our estimated proved reserves. Based on oil and gas prices in effect on March 31,
2009 ($3.63 per MMBtu for Henry Hub gas and $49.65 per barrel for West Texas Intermediate oil,
adjusted for differentials), the unamortized cost of our oil and gas properties exceeded the
ceiling limit and we recorded a $114.8 million ($71.9 million after tax) impairment to our oil and
gas properties. Also, at December 31, 2008, the unamortized cost of our oil and gas properties
exceeded the ceiling limit based on oil and gas prices in effect ($5.71 per MMBtu for Henry Hub gas
and $44.60 per barrel for West Texas Intermediate oil, adjusted for differentials). Therefore, we
recorded a $237.2 million ($148.6 million after tax) impairment to our oil and gas properties at
December 31, 2008. No assurance can be given that we will not experience a capitalized ceiling
impairment charge in future periods. In addition, capitalized ceiling impairment charges may occur
if estimates of proved hydrocarbon reserves are substantially reduced or estimates of future
development costs increase significantly. See Item 1A. Risk Factors Exploratory drilling is a
speculative activity that may not result in commercially productive reserves and may require
expenditures in excess of budgeted amounts, Item 1A. Risk Factors We need to replace our
reserves at a faster rate than companies whose reserves have longer production lives. Our failure
to replace our reserves would result in decreasing reserves and production over time and Item 1A.
Risk Factors Lower oil and natural gas prices may cause us to record ceiling limitation
writedowns, which would reduce our stockholders equity.
Additionally, the modernization of SEC oil and gas reporting rules eliminated the ability to use
subsequent pricing in assessing the need for a ceiling limitation
writedown. This could cause us to record a ceiling limitation writedown that would
not be required if subsequent pricing were used.
Asset Retirement Obligations
We have significant obligations to plug and abandon our oil and natural gas wells and related
equipment. Liabilities for asset retirement obligations are recorded at fair value in the period
incurred. The related asset value is increased by the same amount. Asset retirement costs
included in the carrying amount of the related asset are subsequently allocated to expense as part
of our depletion calculation. See - Oil and Natural Gas Property. Additionally, increases in
the discounted asset retirement liability resulting from the passage of time are reported as
accretion of discount on asset retirement obligations expense on our Consolidated Statement of
Operations.
62
Estimating future asset retirement obligations requires us to make estimates and judgments
regarding timing, existence of a liability, as well as what constitutes adequate restoration. We
use the present value of estimated cash flows related to our asset retirement obligations to
determine the fair value. Present value calculations inherently incorporate numerous assumptions
and judgments, which include the ultimate retirement and restoration costs, inflation factors,
credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory,
environmental and political environments. To the extent future revisions to these assumptions
impact the present value of our existing asset retirement obligation liability, a corresponding
adjustment will be made to the carrying cost of the related asset.
Income Taxes
Deferred tax assets are recognized for temporary differences in financial statement and tax
basis amounts that will result in deductible amounts and carry-forwards in future years. Deferred
tax liabilities are recognized for temporary differences that will result in taxable amounts in
future years. Deferred tax assets and liabilities are measured using enacted tax law and tax
rate(s) for the year in which we expect the temporary differences to be deducted or settled. The
effect of a change in tax law or rates on the valuation of deferred tax assets and liabilities is
recognized in income in the period of enactment. Deferred tax assets are reduced by a valuation
allowance when, in the opinion of management, it is more likely than not that some portion or all
of the deferred tax assets will not be realized. Significant future
taxable income would be required to realize this net tax asset.
Estimating the amount of the valuation allowance is dependent on estimates of future taxable
income, alternative minimum tax income, and changes in stockholder ownership that would trigger
limits on use of net operating losses under Internal Revenue Code Section 382.
We have a significant deferred tax asset associated with net operating loss carryforwards
(NOLs). It is more likely than not that we will not use all of these NOLs to offset current tax
liabilities in future years. We have, therefore, established a valuation allowance on the portion
of the NOLs that may expire unused based on estimates of the reversal of our temporary differences.
Our NOLs are more fully described in Item 8. Financial Statements and Supplementary Data Note
8. Income Taxes.
Revenue Recognition
We derive revenue primarily from the sale of the oil and natural gas that we produce, hence
our revenue recognition policy for these sales is significant.
We recognize revenue from the sale of oil using the sales method of accounting. Under this
method, we recognize revenue when we deliver oil and title transfers.
We recognize revenue from the sale of natural gas using the entitlements method of accounting.
Under this method, we recognize revenue based on our entitled ownership percentage of sales of
natural gas delivered to purchasers. Gas imbalances occur when we sell more or less than our
entitled ownership percentage of total natural gas production. When we receive less than our
entitled share, a receivable is recorded. When we receive more than our entitled share, a
liability is recorded.
Settlements for hydrocarbon sales can occur up to two months after the end of the month in
which the oil, natural gas or other hydrocarbon products were produced. We estimate and accrue for
the value of these sales using information available to us at the time our financial statements are
generated. Differences are reflected in the accounting period that payments are received from the
purchaser.
Derivative Instruments and Hedging Activities
Periodically, we use derivative instruments to manage our market risks associated with
fluctuations in oil and natural gas prices. We periodically enter into derivative contracts,
including price swaps, caps and floors, which require payments to (or receipts from) counterparties
based on the differential between a fixed price and a variable price for a fixed quantity of oil
and natural gas without the exchange of underlying volumes. The notional amounts of these
financial instruments are based on expected production from existing wells.
63
In the past, we similarly use derivative contracts to manage our risks associated with
interest rate fluctuations on long-term debt.
All derivatives are accounted for in accordance with FASB ASC 815 and carried at
fair value on the balance sheet. We utilize the mark-to-market methodology to account for our
hedges. Mark-to-market accounting requires that both derivative settlements and unrealized gains
(losses) are recorded on the consolidated statement of operations. We elected to include all
derivative settlement and unrealized gains (losses) within revenues.
New Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards Board Auditing Standard Codification Topic 820 Fair Value Measurements and
Disclosures (FASB ASC 820), which provides expanded guidance for using fair value to measure
assets and liabilities. FASB ASC 820 establishes a hierarchy for data used to value assets and
liabilities, and requires additional disclosures about the extent to which a company measures
assets and liabilities at fair value, the information used to measure fair value, and the effect of
fair value measurements on earnings. Implementation of FASB ASC 820 was required on January 1, 2008
for financial assets and liabilities, as well as other assets and liabilities that are carried at
fair value on a recurring basis in financial statements. The FASB Staff deferred implementation for
other non-financial assets and liabilities for one year. Examples of non-financial assets and
liabilities are asset retirement obligations and non-financial assets and liabilities initially
measured at fair value in a business combination. The adoption of FASB ASC 820 on January 1, 2010 did not have a
material impact on the financial statements.
On December 31, 2008, the SEC published the final rules and interpretations updating its oil
and gas reporting requirements. Many of the revisions are updates to definitions in the existing
oil and gas rules to make them consistent with the petroleum resource management system, which is a
widely accepted standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include nontraditional resources in
reserves, the use of new technology for determining reserves, permitting disclosure of probable and
possible reserves, and changes to the pricing used to determine reserves in that companies must use
a 12-month average price. The average is calculated using the first-day-of-the-month price for each
of the 12 months that make up the reporting period. The SEC will require companies to comply with
the amended disclosure requirements for registration statements filed after January 1, 2010, and
for annual reports for fiscal years ending on or after December 15, 2009. Early adoption was not
permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932
Extractive Activities Oil and Gas (FASB ASC 932) provides guidance for oil and natural gas
reserve related disclosures in the financial statements. Adoption of the new requirements did not
have a material impact on Brighams financial statements.
In May 2009, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 165 Subsequent Events (SFAS 165). SFAS 165 establishes general
standards of accounting for and disclosure of events that occur after the balance sheet date but
before financial statements are issued or are available to be issued. SFAS 165 will apply with
respect to interim or annual reporting periods ending after June 15, 2009. See Note 16 Subsequent
Events.
In June 2009, the Financial Accounting Standards Board issued Financial Accounting Standards
Board Accounting Standards Codification Topic 105 Generally Accepted Accounting Principles (FASB
ASC 105). FASB ASC 105 sets forth that the Financial Accounting Standards Board Accounting
Standards Codification (ASC) is the exclusive authoritative reference for nongovernmental U.S. GAAP
for use in financial statements issued for interim and annual periods ending after September 15,
2009, except for SEC rules and interpretive releases, which also are authoritative GAAP for SEC
registrants. The change was established by FASB Statement of Financial Accounting Standards No.
168 The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting
Principles (FAS 168), which divides nongovernmental U.S. GAAP into the authoritative Codification
and guidance that is nonauthoritative, doing away with the previous four-level hierarchy. FASB ASC
105 is effective for financial statements for interim or annual reporting periods ending after
September 15, 2009. FASB ASC 105 was not intended to change or alter existing GAAP, and the
Companys adoption did not have any impact on its consolidated financial statements other than to
modify certain existing disclosures. Upon adoption, the Company began to use the new guidelines
and numbering system prescribed by the FASB ASC when referring to GAAP in the third quarter of
fiscal 2009.
64
Other Matters
Commodity Prices
Changes in commodity prices significantly affect our capital resources, liquidity and
operating results. Price changes directly affect revenues and can indirectly impact expected
production by changing the amount of capital available we have to reinvest in our exploration and
development activities. Commodity prices are impacted by many factors that are outside of our
control. Over the past few of years, commodity prices have been highly volatile. We expect that
commodity prices will continue to fluctuate significantly in the future. As a result, we cannot
accurately predict future oil and natural gas prices, and therefore, we cannot determine what
effect increases or decreases will have on our capital program, production volumes and future
revenues.
The prices we receive for our oil production are based on global market conditions. Our
average pre-hedged sales price for oil in 2009 was $54.79 per barrel, which was 38% lower than the
prices we received in 2008. Significant factors that will impact 2010 oil prices include the pace
at which the domestic and global economies recover from the current recession, the extent to which
members of the Organization of Petroleum Exporting Countries and other oil exporting nations are
able to manage oil supply through export quotas and developments in the Middle East Countries.
Natural gas prices are primarily driven by North American market forces. However, global LNG
shipments can impact North American markets to the extent cargoes are diverted from Asia or Europe
to North America. Factors that can affect the price of natural gas are changes in market demands,
overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis
differentials and other factors. Over the past three years, natural gas prices have been volatile.
Our average pre-hedged sales price for natural gas in 2009 was $4.01 per Mcf, which was 56% lower
than the price we received in 2008. Natural gas prices in 2010 will be dependent upon many factors
including the balance between North American supply and demand.
Derivative Instruments
Our results of operations and operating cash flow are impacted by changes in market prices for
oil and gas. We believe the use of derivative instruments, although not free of risk, allows us to
reduce our exposure to oil and natural gas sales price fluctuations and thereby achieve a more
predictable cash flow. While the use of derivative instruments limits the downside risk of adverse
price movements, their use may also limit future revenues from favorable price movements.
Moreover, our derivative contracts generally do not apply to all of our production and thus provide
only partial price protection against declines in commodity prices. We expect that the amount of
our derivative contracts will vary from time to time. See Item 1A. Risk Factors Our hedging
activities may prevent us from benefiting from price increases and may expose us to other risks
and Item 7A. Quantitative and Qualitative Disclosures About Market Risk Derivative Instruments
and Hedging Activities.
Effects of Inflation and Changes in Prices
Our results of operations and cash flows are affected by changing oil and natural gas prices.
If the price of oil and natural gas increases (decreases), there could be a corresponding increase
(decrease) in revenues as well as the operating costs that we are required to bear for operations.
Environmental and Other Regulatory Matters
Our business is subject to certain federal, state and local laws and regulations relating to
the exploration for and the development, production and marketing of oil and natural gas, as well
as environmental and safety matters. Many of these laws and regulations have become more stringent
in recent years, often imposing greater liability on a larger number of potentially responsible
parties. Although we believe that we are in substantial compliance with all applicable laws and
regulations, the requirements imposed by laws and regulations are frequently changed and subject to
interpretation, and we cannot predict the ultimate cost of compliance with these requirements or
their effect on our operations. Any suspensions, terminations or inability to meet applicable
bonding requirements could materially adversely affect our financial condition and operations.
Although significant expenditures may be required to comply with governmental laws and regulations
applicable to us, compliance has not had a material adverse effect on our earnings or competitive
position. Future regulations may add to the cost of, or significantly limit, drilling activity.
See Item 1A. Risk Factors We are subject to various governmental regulations and environmental
risks that may cause us to incur substantial costs and Item 1. Business Governmental
Regulation and Item 1. Business Environmental Matters.
65
|
|
|
Item 7A. |
|
Quantitative and Qualitative Disclosures About Market Risk |
Management Opinion Concerning Derivative Instruments
We use derivative instruments to manage exposure to commodity prices and interest rate risks.
Our objectives for holding derivatives are to achieve a relatively consistent level of cash flow to
support a portion of our planned capital spending. Our use of derivative instruments for hedging
activities could materially affect our results of operations in particular quarterly or annual
periods since such instruments can limit our ability to benefit from favorable price movements. We
do not enter into derivative instruments for trading purposes.
Fair Value of Derivative Contracts
We use the mark-to-market accounting methodology to account for our hedges. At the end of
each quarter, our derivatives are marked-to-market to reflect the current fair value and both
derivative settlements and unrealized gains (losses) are recorded on the consolidated statement of
operations. We include all derivative settlement and unrealized gains (losses) within revenue.
66
The fair values of our derivative contracts are determined based on counterparties estimates
and valuation models. We did not change our valuation methodology during the year ended December
31, 2009. The following table reconciles the changes that occurred in the fair values of our open
derivative contracts during 2009.
|
|
|
|
|
|
|
Fair Value of |
|
|
|
Undesignated |
|
|
|
Derivative |
|
|
|
Contracts |
|
Estimated fair value of open contracts at December 31, 2008 |
|
$ |
5,337 |
|
|
|
|
|
Changes in fair values of derivative contracts: |
|
|
|
|
Natural gas collars |
|
$ |
4,149 |
|
Oil collars |
|
|
(3,216 |
) |
Settlements of derivative contracts that were open at December 31, 2008: |
|
|
|
|
Natural gas collars |
|
$ |
(7,118 |
) |
Oil collars
|
|
|
(1,127 |
) |
|
|
|
|
|
Estimated fair value of open contracts at December 31, 2009 |
|
$ |
(1,975 |
) |
|
|
|
|
Derivative Instruments and Hedging Activities
Our primary commodity market risk exposure is to changes in the prices that we receive for our
oil and natural gas production. The market prices for oil and natural gas have been highly
volatile and are likely to continue to be highly volatile in the future. As such, we employ
established policies and procedures to manage our exposure to fluctuations in the sales prices we
receive for our oil and natural gas production via using derivative instruments.
While the use of derivative instruments limits the downside risk of adverse price movements,
their use may also limit future revenues from favorable price movements. Moreover, our derivative
contracts generally do not apply to all of our production and thus provide only partial price
protection against declines in commodity prices. We expect that the amount of our derivative
contracts will vary from time to time.
During 2009, we were party to natural gas costless collars, natural gas three-way costless
collars, natural gas swaps, oil costless collars and oil swaps. See Item 8. Financial Statements and Supplementary Data Note 11 Derivative Instruments and Hedging Activities for additional information regarding our derivative contracts.
We use costless collars to establish floor (purchased put option) and ceiling prices (written
call option) on our anticipated future oil and natural gas production. We neither receive nor pay
net premiums when we enter into these option arrangements. These contracts are settled monthly.
When the settlement price for a period is above the ceiling price (written call option), we pay our
counterparty. When the settlement price for a period is below the floor price (purchased put
option), our counterparty is required to pay us. All hedges are accounted for using mark-to-market
accounting.
A three-way costless collar consists of a costless collar (purchased put option and written
call option) plus a put (written put) sold by us with a price below the floor price (purchased put
option) of the costless collar. We neither receive nor pay net premiums when we enter into these
option arrangements. These contracts are settled monthly. The written put requires us to make a
payment to our counterparty if the settlement price for a period is below the written put price.
Combining the costless collar (purchased put option and written call option) with the written put
results in us being entitled to a net payment equal to the difference between the floor price
(purchased put option) of the costless collar and the written put price if the settlement price is
equal to or less than the written put price. If the settlement price is greater than the written
put price, the result is the same as it would have been with a costless collar. This strategy
enables us to increase the floor and the ceiling price of the collar beyond the range of a
traditional costless collar while offsetting the associated cost with the sale of the written put.
All hedges are accounted for using mark-to-market accounting.
We use swaps to fix the sales price for our anticipated future natural gas production. Upon
settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating
market price, as defined in each instrument. These instruments are settled monthly. When the
floating price exceeds the fixed price for a contract month, we pay our counterparty. When the
fixed price exceeds the floating price, our counterparty is required to make a payment to us.
Natural gas derivative transactions are generally settled based upon the average reported
settlement prices on the NYMEX for the last three trading days of a particular contract month. Oil
derivative transactions are generally
settled based on the average reported settlement prices on the NYMEX for each trading day of a
particular calendar month.
67
The following table reflects our open derivative contracts at December 31, 2009, the
associated volumes and the corresponding weighted average NYMEX reference price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMbtu) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Natural Gas Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
01/01/10 03/31/10 |
|
|
210,000 |
|
|
$ |
5.75 |
|
|
$ |
7.05 |
|
04/01/10 09/30/10 |
|
|
420,000 |
|
|
$ |
5.75 |
|
|
$ |
7.30 |
|
10/01/10 03/31/11 |
|
|
240,000 |
|
|
$ |
6.50 |
|
|
$ |
8.25 |
|
04/01/10 09/30/10 |
|
|
240,000 |
|
|
$ |
5.75 |
|
|
$ |
7.00 |
|
01/01/10 12/31/10 |
|
|
840,000 |
|
|
$ |
5.15 |
|
|
$ |
7.00 |
|
04/01/10 09/30/10 |
|
|
300,000 |
|
|
$ |
5.50 |
|
|
$ |
6.65 |
|
10/01/10 03/31/11 |
|
|
420,000 |
|
|
$ |
6.40 |
|
|
$ |
7.80 |
|
01/01/11 12/31/11 |
|
|
360,000 |
|
|
$ |
5.75 |
|
|
$ |
7.65 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
Purchased |
|
|
Written |
|
|
Written |
|
|
|
Gas |
|
|
Put |
|
|
Call |
|
|
Put |
|
Settlement Period |
|
(MMbtu) |
|
|
(Nymex) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Natural Gas Three Way Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/10 03/31/10 |
|
|
210,000 |
|
|
$ |
8.00 |
|
|
$ |
10.00 |
|
|
$ |
5.50 |
|
01/01/10 03/31/10 |
|
|
180,000 |
|
|
$ |
5.75 |
|
|
$ |
7.00 |
|
|
$ |
3.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude |
|
|
Purchased |
|
|
Written |
|
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(Bbls) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
01/01/10 12/31/10 |
|
|
120,000 |
|
|
$ |
48.70 |
|
|
$ |
80.00 |
|
01/01/10 05/31/10 |
|
|
50,000 |
|
|
$ |
57.50 |
|
|
$ |
75.95 |
|
06/01/10 12/31/10 |
|
|
56,000 |
|
|
$ |
57.50 |
|
|
$ |
82.15 |
|
01/01/10 12/31/10 |
|
|
54,000 |
|
|
$ |
60.00 |
|
|
$ |
86.50 |
|
01/01/11 12/31/11 |
|
|
84,000 |
|
|
$ |
65.00 |
|
|
$ |
88.25 |
|
01/01/10 03/31/10 |
|
|
6,000 |
|
|
$ |
65.00 |
|
|
$ |
87.50 |
|
07/01/10 09/30/10 |
|
|
6,000 |
|
|
$ |
70.00 |
|
|
$ |
87.25 |
|
10/01/10 12/31/10 |
|
|
3,000 |
|
|
$ |
70.00 |
|
|
$ |
88.50 |
|
01/01/10 03/31/10 |
|
|
9,000 |
|
|
$ |
60.00 |
|
|
$ |
91.75 |
|
04/01/10 09/30/10 |
|
|
18,000 |
|
|
$ |
60.00 |
|
|
$ |
91.40 |
|
01/01/10 12/31/10 |
|
|
60,000 |
|
|
$ |
60.00 |
|
|
$ |
88.80 |
|
01/01/11 12/31/11 |
|
|
60,000 |
|
|
$ |
60.00 |
|
|
$ |
97.25 |
|
01/01/10 06/30/10 |
|
|
30,000 |
|
|
$ |
60.00 |
|
|
$ |
103.75 |
|
01/01/11 12/31/11 |
|
|
60,000 |
|
|
$ |
65.00 |
|
|
$ |
108.00 |
|
01/01/11 06/30/11 |
|
|
18,000 |
|
|
$ |
65.00 |
|
|
$ |
97.50 |
|
01/01/10 12/31/10 |
|
|
36,000 |
|
|
$ |
60.00 |
|
|
$ |
96.00 |
|
01/01/10 12/31/10 |
|
|
24,000 |
|
|
$ |
60.00 |
|
|
$ |
100.00 |
|
68
The following table reflects commodity derivative contracts entered into subsequent to
December 31, 2009, the associated volumes and the corresponding weighted average NYMEX reference
price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMbtu) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Natural Gas Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 12/31/11 |
|
|
480,000 |
|
|
$ |
5.75 |
|
|
$ |
7.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude |
|
|
Purchased |
|
|
Written |
|
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(Bbls) |
|
|
(Nymex) |
|
|
(Nymex) |
|
Oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
07/01/10 12/31/10 |
|
|
12,000 |
|
|
$ |
65.00 |
|
|
$ |
107.70 |
|
01/01/11 12/31/11 |
|
|
48,000 |
|
|
$ |
70.00 |
|
|
$ |
106.80 |
|
03/01/10 12/31/10 |
|
|
40,000 |
|
|
$ |
70.00 |
|
|
$ |
101.75 |
|
03/01/10 08/31/10 |
|
|
18,000 |
|
|
$ |
70.00 |
|
|
$ |
99.00 |
|
01/01/11 12/31/11 |
|
|
48,000 |
|
|
$ |
75.00 |
|
|
$ |
102.60 |
|
07/01/11 12/31/11 |
|
|
12,000 |
|
|
$ |
75.00 |
|
|
$ |
103.00 |
|
04/01/10 06/30/10 |
|
|
30,000 |
|
|
$ |
65.00 |
|
|
$ |
89.90 |
|
07/01/10 12/31/10 |
|
|
30,000 |
|
|
$ |
65.00 |
|
|
$ |
94.25 |
|
01/01/11 06/30/11 |
|
|
24,000 |
|
|
$ |
70.00 |
|
|
$ |
92.50 |
|
07/01/11 09/30/11 |
|
|
9,000 |
|
|
$ |
70.00 |
|
|
$ |
95.00 |
|
10/01/11 12/31/11 |
|
|
6,000 |
|
|
$ |
70.00 |
|
|
$ |
96.35 |
|
01/01/11 02/28/11 |
|
|
10,000 |
|
|
$ |
70.00 |
|
|
$ |
92.00 |
|
Interest Rate Risk
At December 31, 2009, we had $169.1 million of short term and long term debt, all of which was
fixed rate debt. Our fixed rate long term debt consists of our $159.0 million in Senior Notes.
Our fixed rate short term debt consists of $10.1 million in Series A preferred stock.
The interest rate that we pay on amounts borrowed under our Senior Credit Facility is derived
from the Eurodollar rate and a margin that is applied to the Eurodollar rate. This calculation was
performed using the one month Eurodollar rate on December 31, 2009, which was 0.32%. The margin
that we pay is based upon the percentage of our available borrowing base that we utilize at the
beginning of the quarter. At December 31, 2009, the borrowing base for our Senior Credit Facility
was $110 million. Since we had no outstanding balance under our Senior Credit Facility at December
31, 2009, we were utilizing 0% of our available borrowing base. At this level of utilization, our
Senior Credit Facility requires us to pay a margin of 2.50%. Our all-in interest rate that we
would be required to pay on the amounts borrowed under our Senior Credit Facility would be 2.82%.
A 10% increase in the Eurodollar rate would equal approximately 3 basis points. Such an
increase in the Eurodollar rate would change our annual interest expense by approximately
$33,000, assuming borrowed amounts under our Senior Credit Facility remained constant at $110
million.
We are required to pay the dividends on our Series A preferred stock in cash at a rate of 6%
per annum. The fair value of the Series A mandatorily redeemable preferred stock at December 31,
2009 was approximately $10.1 million.
69
|
|
|
Item 8. |
|
Financial Statements and Supplementary Data |
Our Consolidated Financial Statements required by this item are included on the pages
immediately following the Index to Financial Statements appearing on page F-1.
|
|
|
Item 9. |
|
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
|
|
|
Item 9A. |
|
Controls and Procedures |
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
As of December 31, 2009, our management, including our principal executive officer and
principal financial officer, has evaluated the effectiveness of the design and operation of our
disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of
1934. There are inherent limitations to the effectiveness of any system of disclosure controls and
procedures, including the possibility of human error and the circumvention or overriding of the
controls and procedures. Accordingly, even effective disclosure controls and procedures can only
provide reasonable assurance of achieving their control objectives. Based upon and as of the date
of the evaluation, our principal executive officer and our principal financial officer concluded
that the design and operation of our disclosure controls and procedures were effective at a
reasonable assurance level in that they ensure that information required to be disclosed by us in the reports that we file or
submit under the Securities and Exchange Act of 1934 is (1) recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms, and (2)
accumulated and communicated to our management,
including our Chief Executive Officer and Chief Financial Officer, as
appropriate to allow timely decisions regarding required disclosure..
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its
inherent limitations, internal control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness to future periods are subject
to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate. Under the supervision and
with the participation of our management, including our principal executive officer and principal
financial officer, we conducted an evaluation of the effectiveness of our internal control over
financial reporting based on the framework in Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation
under the framework in Internal Control Integrated Framework issued by the COSO, our management
concluded that our internal control over financial reporting was effective as of December 31, 2009.
The effectiveness of our internal control over financial reporting as of December 31, 2009 has
been audited by KPMG LLP, an independent registered public accounting firm, as stated in their
report, which is included herein.
Changes in Internal Control over Financial Reporting
There has been no change in our internal control over financial reporting during the fourth
quarter of 2009 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
|
|
|
Item 9B. |
|
Other Information |
None.
70
PART III
|
|
|
Item 10. |
|
Directors, Executive Officers and Corporate Governance |
The information required by this item is incorporated by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009.
Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect
to Brighams executive officers is set forth in Part I of this report.
|
|
|
Item 11. |
|
Executive Compensation |
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009.
|
|
|
Item 12. |
|
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009. See Item 5. Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities, which sets forth certain
information with respect to our equity compensation plans.
|
|
|
Item 13. |
|
Certain Relationships and Related Transactions, and Director Independence |
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009.
|
|
|
Item 14. |
|
Principal Accounting Fees and Services |
The information required by this item is incorporated herein by reference to the 2010 Proxy
Statement, which will be filed with the Securities and Exchange Commission not later than 120 days
subsequent to December 31, 2009.
PART IV
|
|
|
Item 15. |
|
Exhibits, Financial Statement Schedules |
|
(a) |
|
1. Consolidated Financial Statements: See Index to Financial Statements on page F-1. |
|
2. |
|
No schedules are required. |
The exhibits listed in the accompanying Index to Exhibits are filed or incorporated by
reference as part of the annual report.
71
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and
gas industry and in this report. The definitions of proved developed reserves, proved reserves and
proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule
4-10(a)(2-4) of Regulation S-X.
3-D seismic. The method by which a three dimensional image of the earths subsurface is
created through the interpretation of reflection seismic data collected over surface grid. 3-D
seismic surveys allow for a more detailed understanding of the subsurface than do conventional
surveys and contribute significantly to field appraisal, development and production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil
or other liquid hydrocarbons.
Boe. A barrel of oil equivalent is approximately six thousand cubic feet of typical natural
gas.
Completion. The installation of permanent equipment for the production of oil or natural gas.
Completion of the well does not necessarily mean the well will be profitable.
Completion Rate. The number of wells on which production casing has been run for a completion
attempt as a percentage of the number of wells drilled.
Development Well. A well drilled within the proved area of an oil or natural gas reservoir to
the depth of a stratigraphic horizon known to be productive.
Dry Well. A well found to be incapable of producing either oil or natural gas in sufficient
quantities to justify completion of an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area,
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.
Fault. A break in the rocks along which there has been movement of one side relative to the
other side.
Fault Block. A body of rocks bounded by one or more faults.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a
working interest.
Hydraulic fracturing. A stimulation treatment routinely performed on oil and gas wells in
low-permeability reservoirs. Specially engineered fluids are pumped at high pressure and rate into the
reservoir interval to be treated, causing a vertical fracture to open. The wings of the fracture
extend away from the wellbore in opposing directions according to the natural stresses within the
formation.
IP Rate. Initial Production Rate. The peak 24 hour production rate of a well, usually achieved within the first few days after being brought on line to production.
Lease Operating Expenses. The expenses, usually recurring, which pay for operating the wells
and equipment on a producing lease.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet of natural gas.
72
MMBbl. One million barrels of oil or other liquid hydrocarbons.
Mcfe. One thousand cubic feet of natural gas equivalents.
MMBtu. One million Btu, or British Thermal Units. One British Thermal Unit is the quantity of
heat required to raise the temperature of one pound of water by one degree Fahrenheit.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalents.
Net Acres or Net Wells. Gross acres or wells multiplied, in each case, by the percentage
working interest we own.
Net Production. Production that we own less royalties and production due others.
Oil. Crude oil, condensate or other liquid hydrocarbons.
Operator. The individual or company responsible for the exploration, development, and
production of an oil or gas well or lease.
Pay. The vertical thickness of an oil and gas producing zone. Pay can be measured as either
gross pay, including non-productive zones or net pay, including only zones that appear to be
productive based upon logs and test data.
Pre-tax PV10%. The pre-tax present value of estimated future revenues to be generated from
the production of proved reserves calculated in accordance with Securities and Exchange Commission
guidelines, net of estimated production and future development costs, using prices and costs as of
the date of estimation without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and depreciation, depletion and
amortization, and discounted using an annual discount rate of 10%.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods.
Proved Reserves. 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.
Proved Undeveloped Reserves. 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.
73
Royalty. An interest in an oil and gas lease that gives the owner of the interest the right
to receive a portion of the production from the leased acreage (or of the proceeds of the sale
thereof), but generally does not require the owner to pay any portion of the costs of drilling or
operating the wells on the leased acreage. Royalties may be either landowners royalties, which
are reserved by the owner of the leased acreage at the time the lease is granted, or overriding
royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to
a subsequent owner.
Spud. Start (or restart) drilling a new well.
Standardized Measure. The after-tax present value of estimated future revenues to be
generated from the production of proved reserves calculated in accordance with Securities and
Exchange Commission guidelines, net of estimated production and future development costs, using
prices and costs as of the date of estimation without future escalation, without giving effect to
non-property related expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.
Trend. A geographical area that has been known to contain certain types of combinations of
reservoir rock, sealing rock and trap types containing commercial amounts of hydrocarbons.
Working Interest. An interest in an oil and gas lease that gives the owner of the interest
the right to drill for and produce oil and natural gas on the leased acreage and requires the owner
to pay a share of the costs of drilling and production operations.
74
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, hereunder
duly authorized, as of February 26, 2010.
|
|
|
|
|
|
BRIGHAM EXPLORATION COMPANY
|
|
|
By /s/ BEN M. BRIGHAM
|
|
|
Ben M. Brigham |
|
|
Chief Executive Officer,
President and Chairman of the Board |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, the following persons on
behalf of the Registrant and in the capacity indicated have signed this report below as of
February 26, 2010.
|
|
|
/s/ BEN M. BRIGHAM
|
|
Chief Executive Officer, President and Chairman of the Board |
|
|
(Principal Executive Officer) |
|
|
|
/s/ EUGENE B. SHEPHERD, JR.
|
|
Executive Vice President and Chief Financial Officer |
|
|
(Principal Financial and Accounting Officer) |
|
|
|
/s/ DAVID T. BRIGHAM
|
|
Executive Vice President Land and Administration and Director |
|
|
|
|
|
|
/s/ HAROLD D. CARTER
|
|
Director |
|
|
|
|
|
|
/s/ STEPHEN C. HURLEY
|
|
Director |
|
|
|
|
|
|
/s/ STEPHEN P. REYNOLDS
|
|
Director |
|
|
|
|
|
|
/s/ HOBART A. SMITH
|
|
Director |
|
|
|
|
|
|
/s/ SCOTT W. TINKER
|
|
Director |
|
|
|
75
BRIGHAM EXPLORATION COMPANY
INDEX TO FINANCIAL STATEMENTS
|
|
|
|
|
|
|
Page |
|
|
|
|
|
|
F-2 |
|
|
|
|
|
|
|
|
|
F-4 |
|
|
|
|
|
|
|
|
|
F-5 |
|
|
|
|
|
|
|
|
|
F-6 |
|
|
|
|
|
|
|
|
|
F-7 |
|
|
|
|
|
|
|
|
|
F-8 |
|
|
|
|
|
|
|
|
|
F-29 |
|
|
|
|
|
|
|
|
|
F-31 |
|
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Brigham Exploration Company:
We have audited the accompanying consolidated balance sheets of Brigham Exploration Company
and subsidiaries (the Company) as of December 31, 2009 and 2008, and the related consolidated
statements of operations, stockholders equity, and cash flows for each of the years in the
three-year period ended December 31, 2009. These consolidated financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Brigham Exploration Company and subsidiaries as of
December 31, 2009 and 2008, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2009, in conformity with U.S. generally
accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), Brigham Exploration Companys internal control over financial
reporting as of December 31, 2009, based on criteria established in Internal Control Integrated
Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
and our report dated February 26, 2010 expressed an unqualified opinion on the effectiveness of the
Companys internal control over financial reporting.
(signed) KPMG LLP
Dallas, Texas
February 26, 2010
F-2
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Brigham Exploration Company:
We have audited Brigham Exploration Companys (the Company) internal control over financial
reporting as of December 31, 2009, based on criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Companys management is responsible for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on the Companys internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, and testing
and evaluating the design and operating effectiveness of internal control based on the assessed
risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with Generally Accepted Accounting Principles. A
companys internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Brigham Exploration Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2009, based on criteria established in
Internal Control Integrated Framework, issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Brigham Exploration Company and
subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of
operations, stockholders equity, and cash flows for each of the years in the three-year period
ended December 31, 2009, and our report dated February 26, 2010 expressed an unqualified opinion on
those consolidated financial statements.
(signed) KPMG LLP
Dallas, Texas
February 26, 2010
F-3
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
40,781 |
|
|
$ |
40,043 |
|
Restricted cash |
|
|
|
|
|
|
555 |
|
Accounts receivable |
|
|
21,194 |
|
|
|
24,558 |
|
Short term investments |
|
|
80,093 |
|
|
|
|
|
Derivative assets |
|
|
1,152 |
|
|
|
5,140 |
|
Inventory |
|
|
14,087 |
|
|
|
6,070 |
|
Other current assets |
|
|
1,132 |
|
|
|
2,154 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
158,439 |
|
|
|
78,520 |
|
|
|
|
|
|
|
|
Oil and natural gas properties, using the full cost method of accounting |
|
|
|
|
|
|
|
|
Proved |
|
|
619,920 |
|
|
|
632,275 |
|
Unproved |
|
|
76,309 |
|
|
|
106,006 |
|
Accumulated depletion |
|
|
(365,496 |
) |
|
|
(333,442 |
) |
|
|
|
|
|
|
|
|
|
|
330,733 |
|
|
|
404,839 |
|
|
|
|
|
|
|
|
Other property and equipment, net |
|
|
3,025 |
|
|
|
1,873 |
|
Deferred loan fees |
|
|
5,213 |
|
|
|
3,122 |
|
Other noncurrent assets |
|
|
846 |
|
|
|
702 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
498,256 |
|
|
$ |
489,056 |
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
19,251 |
|
|
$ |
14,297 |
|
Royalties payable |
|
|
8,268 |
|
|
|
6,859 |
|
Accrued drilling costs |
|
|
15,498 |
|
|
|
19,768 |
|
Participant advances received |
|
|
6,949 |
|
|
|
2,226 |
|
Series A Preferred Stock, mandatorily redeemable, $.01 par value,
$20 stated and redemption value, 2,250,000 shares authorized,
505,051 shares issued and outstanding at December 31,
2009 |
|
|
10,101 |
|
|
|
|
|
Other current liabilities |
|
|
7,706 |
|
|
|
5,065 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
67,773 |
|
|
|
48,215 |
|
|
|
|
|
|
|
|
Senior Notes |
|
|
158,968 |
|
|
|
158,730 |
|
Senior credit facility |
|
|
|
|
|
|
145,000 |
|
Series A Preferred Stock, mandatorily redeemable, $.01 par value, $20 stated and redemption value, 2,250,000 shares authorized, 505,051 shares issued and outstanding at December 31, 2008 |
|
|
|
|
|
|
10,101 |
|
Deferred income taxes |
|
|
|
|
|
|
149 |
|
Other noncurrent liabilities |
|
|
7,232 |
|
|
|
5,592 |
|
Commitments and contingencies (Note 10) |
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Common stock, $.01 par value, 180 million shares authorized, 99,593,075
and 45,829,277 shares issued and 99,351,825 and 45,686,295 shares
outstanding at December 31, 2009 and 2008, respectively |
|
|
996 |
|
|
|
458 |
|
Additional paid-in capital |
|
|
479,077 |
|
|
|
212,473 |
|
Treasury stock, at cost; 241,250 and 142,982 shares at December 31,
2009 and 2008, respectively |
|
|
(2,133 |
) |
|
|
(1,202 |
) |
Accumulated other comprehensive income (loss) |
|
|
(205 |
) |
|
|
|
|
Retained earnings (deficit) |
|
|
(213,452 |
) |
|
|
(90,460 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
264,283 |
|
|
|
121,269 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
498,256 |
|
|
$ |
489,056 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-4
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and natural gas sales |
|
$ |
68,192 |
|
|
$ |
125,108 |
|
|
$ |
120,557 |
|
Gain (loss) on derivatives, net |
|
|
2,064 |
|
|
|
2,548 |
|
|
|
(1,664 |
) |
Other revenue |
|
|
88 |
|
|
|
132 |
|
|
|
88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70,344 |
|
|
|
127,788 |
|
|
|
118,981 |
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
14,655 |
|
|
|
12,363 |
|
|
|
10,704 |
|
Production taxes |
|
|
5,098 |
|
|
|
5,374 |
|
|
|
2,541 |
|
General and administrative |
|
|
9,243 |
|
|
|
9,557 |
|
|
|
9,276 |
|
Depletion of oil and natural gas properties |
|
|
32,054 |
|
|
|
53,498 |
|
|
|
59,079 |
|
Impairment of oil and natural gas properties |
|
|
114,781 |
|
|
|
237,180 |
|
|
|
6,505 |
|
Depreciation and amortization |
|
|
812 |
|
|
|
629 |
|
|
|
613 |
|
Accretion of discount on asset retirement obligations |
|
|
421 |
|
|
|
361 |
|
|
|
379 |
|
Loss on inventory valuation |
|
|
2,196 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
179,260 |
|
|
|
318,962 |
|
|
|
89,097 |
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(108,916 |
) |
|
|
(191,174 |
) |
|
|
29,884 |
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
578 |
|
|
|
191 |
|
|
|
654 |
|
Interest expense, net |
|
|
(16,431 |
) |
|
|
(14,495 |
) |
|
|
(14,622 |
) |
Other income (expense) |
|
|
1,544 |
|
|
|
530 |
|
|
|
1,022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,309 |
) |
|
|
(13,774 |
) |
|
|
(12,946 |
) |
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes |
|
|
(123,225 |
) |
|
|
(204,948 |
) |
|
|
16,938 |
|
Income tax benefit (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
233 |
|
|
|
42,701 |
|
|
|
(6,728 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
233 |
|
|
|
42,701 |
|
|
|
(6,728 |
) |
|
|
|
|
|
|
|
|
|
|
Net Income (loss) |
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
$ |
10,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share available to common stockholders: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
$ |
0.23 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
$ |
0.22 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,110 |
|
Diluted |
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,531 |
|
The accompanying notes are an integral part of these consolidated financial statements.
F-5
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Retained |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
Comprehensive |
|
|
Earnings |
|
|
Total |
|
|
|
Common Stock |
|
|
Paid In |
|
|
Treasury |
|
|
Income |
|
|
(Accumulated |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amounts |
|
|
Capital |
|
|
Stock |
|
|
(Loss) |
|
|
Deficit) |
|
|
Equity |
|
Balance, December 31, 2006 |
|
|
45,090 |
|
|
$ |
451 |
|
|
$ |
203,643 |
|
|
$ |
(662 |
) |
|
$ |
1,006 |
|
|
$ |
61,577 |
|
|
$ |
266,015 |
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,210 |
|
|
|
10,210 |
|
Tax provisions related to cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
480 |
|
|
|
|
|
|
|
480 |
|
Net (gains) losses included in net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,371 |
) |
|
|
|
|
|
|
(1,371 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,319 |
|
Issuance of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of restricted stock |
|
|
90 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of employee stock options |
|
|
124 |
|
|
|
1 |
|
|
|
441 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
442 |
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(192 |
) |
|
|
|
|
|
|
|
|
|
|
(192 |
) |
Vesting of share-based payments |
|
|
|
|
|
|
|
|
|
|
3,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,443 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2007 |
|
|
45,304 |
|
|
$ |
453 |
|
|
$ |
207,526 |
|
|
$ |
(854 |
) |
|
$ |
115 |
|
|
$ |
71,787 |
|
|
$ |
279,027 |
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(162,247 |
) |
|
|
(162,247 |
) |
Tax provisions related to cash flow hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61 |
|
|
|
|
|
|
|
61 |
|
Net (gains) losses included in net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(176 |
) |
|
|
|
|
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(162,362 |
) |
Issuance of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of restricted stock |
|
|
139 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of employee stock options |
|
|
386 |
|
|
|
4 |
|
|
|
2,062 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,066 |
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(348 |
) |
|
|
|
|
|
|
|
|
|
|
(348 |
) |
Vesting of share-based payments |
|
|
|
|
|
|
|
|
|
|
2,886 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,886 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2008 |
|
|
45,829 |
|
|
$ |
458 |
|
|
$ |
212,473 |
|
|
$ |
(1,202 |
) |
|
$ |
|
|
|
$ |
(90,460 |
) |
|
$ |
121,269 |
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(122,992 |
) |
|
|
(122,992 |
) |
Unrealized gains (loss) on investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(205 |
) |
|
|
|
|
|
|
(205 |
) |
Tax benefits (provisions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(123,197 |
) |
Issuance of common stock |
|
|
53,130 |
|
|
|
532 |
|
|
|
261,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
261,725 |
|
Vesting of restricted stock |
|
|
378 |
|
|
|
4 |
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of employee stock options |
|
|
256 |
|
|
|
2 |
|
|
|
1,217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,219 |
|
Repurchases of common stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(931 |
) |
|
|
|
|
|
|
|
|
|
|
(931 |
) |
Vesting of share-based payments |
|
|
|
|
|
|
|
|
|
|
4,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, December 31, 2009 |
|
|
99,593 |
|
|
$ |
996 |
|
|
$ |
479,077 |
|
|
$ |
(2,133 |
) |
|
$ |
(205 |
) |
|
$ |
(213,452 |
) |
|
$ |
264,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-6
BRIGHAM EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
$ |
10,210 |
|
Adjustments to reconcile net income (loss) to cash provided
(used) by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion of oil and natural gas properties |
|
|
32,054 |
|
|
|
53,498 |
|
|
|
59,079 |
|
Impairment of oil and natural gas properties |
|
|
114,781 |
|
|
|
237,180 |
|
|
|
6,505 |
|
Depreciation and amortization |
|
|
812 |
|
|
|
629 |
|
|
|
613 |
|
Stock based compensation |
|
|
2,278 |
|
|
|
1,592 |
|
|
|
1,905 |
|
Write-off of deferred loan costs |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of discount and deferred loan fees |
|
|
1,635 |
|
|
|
1,105 |
|
|
|
968 |
|
Accretion of discount on asset retirement obligations |
|
|
421 |
|
|
|
361 |
|
|
|
379 |
|
Market value adjustment for derivative instruments |
|
|
7,313 |
|
|
|
(6,140 |
) |
|
|
5,831 |
|
Deferred income taxes |
|
|
(233 |
) |
|
|
(42,701 |
) |
|
|
6,728 |
|
Provision for doubtful accounts |
|
|
(19 |
) |
|
|
17 |
|
|
|
|
|
Other noncash items |
|
|
90 |
|
|
|
4 |
|
|
|
(4 |
) |
Changes in working capital and other items: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
3,383 |
|
|
|
(9,966 |
) |
|
|
3,743 |
|
Other current assets |
|
|
803 |
|
|
|
(6,521 |
) |
|
|
1,183 |
|
Accounts and royalties payable |
|
|
6,363 |
|
|
|
2,877 |
|
|
|
(6,197 |
) |
Other current liabilities |
|
|
4,964 |
|
|
|
500 |
|
|
|
(890 |
) |
Noncurrent assets |
|
|
114 |
|
|
|
(330 |
) |
|
|
514 |
|
Noncurrent liabilities |
|
|
(17 |
) |
|
|
(228 |
) |
|
|
(118 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
51,750 |
|
|
|
69,630 |
|
|
|
90,449 |
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and natural gas properties |
|
|
(74,668 |
) |
|
|
(178,637 |
) |
|
|
(132,932 |
) |
Proceeds from sale of oil and natural gas properties |
|
|
|
|
|
|
|
|
|
|
35,446 |
|
Changes in inventory |
|
|
(7,881 |
) |
|
|
|
|
|
|
|
|
Additions to other property and equipment |
|
|
(2,054 |
) |
|
|
(1,472 |
) |
|
|
(707 |
) |
Short term investments |
|
|
(80,298 |
) |
|
|
|
|
|
|
|
|
(Increase) decrease in drilling advances paid |
|
|
(274 |
) |
|
|
798 |
|
|
|
(900 |
) |
Changes to restricted cash |
|
|
555 |
|
|
|
(555 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used by investing activities |
|
|
(164,620 |
) |
|
|
(179,866 |
) |
|
|
(99,093 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock, net of issuance costs |
|
|
261,725 |
|
|
|
|
|
|
|
|
|
Proceeds from exercise of employee stock options |
|
|
1,219 |
|
|
|
2,066 |
|
|
|
472 |
|
Proceeds from Senior Notes offering |
|
|
|
|
|
|
|
|
|
|
34,825 |
|
Repurchases of common stock |
|
|
(931 |
) |
|
|
(348 |
) |
|
|
(192 |
) |
Increase in senior credit facility |
|
|
|
|
|
|
139,500 |
|
|
|
58,800 |
|
Repayment of senior credit facility |
|
|
(145,000 |
) |
|
|
(4,500 |
) |
|
|
(74,700 |
) |
Principal payments on senior subordinated notes |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred loan fees paid and equity costs |
|
|
(3,405 |
) |
|
|
(302 |
) |
|
|
(998 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided (used) by financing activities |
|
|
113,608 |
|
|
|
136,416 |
|
|
|
18,207 |
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
738 |
|
|
|
26,180 |
|
|
|
9,563 |
|
Cash and cash equivalents, beginning of year |
|
|
40,043 |
|
|
|
13,863 |
|
|
|
4,300 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of year |
|
$ |
40,781 |
|
|
$ |
40,043 |
|
|
$ |
13,863 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these consolidated financial statements.
F-7
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Nature of Operations
Brigham Exploration Company is a Delaware corporation formed on February 25, 1997 for the
purpose of exchanging its common stock for the common stock of Brigham, Inc. and the partnership
interests of Brigham Oil & Gas, L.P. (the Partnership). Hereinafter, Brigham Exploration Company
and the Partnership are collectively referred to as Brigham. The Partnership was formed in May
1992 to explore and develop onshore domestic oil and natural gas properties using 3-D seismic
imaging and other advanced technologies. Brighams exploration and development of oil and natural
gas properties is currently focused in the Rocky Mountains, the Gulf Coast, the Anadarko Basin, and
West Texas.
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting
principles in the United States of America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. The most significant estimates relate to proved oil and
natural gas reserve volumes, future development costs, estimates relating to certain oil and
natural gas revenues and expenses, and deferred income taxes. Actual results may differ from those
estimates.
Reclassifications
Certain reclassifications have been made to prior years reported amounts in order to conform with
the current year presentation. These reclassifications did not impact our net income, stockholders
equity or cash flows.
Principles of Consolidation
The accompanying financial statements include the accounts of Brigham and its wholly owned
subsidiaries, and its proportionate share of assets, liabilities and income and expenses of the
limited partnerships in which Brigham, or any of its subsidiaries has a participating interest. All
significant intercompany accounts and transactions have been eliminated.
Cash and Cash Equivalents
Brigham considers all highly liquid financial instruments with an original maturity of three
months or less to be cash equivalents. Restricted cash at December 31, 2008 includes deposits in
an interest bearing escrow account under the terms of a turnkey drilling contract executed during
the third quarter of 2008. There was no restricted cash at December 31, 2009.
Investments
Investments consist primarily of certificates of deposit, corporate debt, and government
securities, all of which are classified as available-for-sale and stated at fair value.
Accordingly, unrealized gains and losses and any related deferred income tax effects are excluded
from earnings and reported as a separate component of stockholders equity. Realized gains or
losses are computed based on specific identification of the securities sold.
F-8
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Inventory
Inventory, which is included in current assets, includes tubular goods and other lease and
well equipment which we plan to utilize in our ongoing exploration and development
activities. Inventory also includes 16,475 barrels of crude oil that was produced in the Williston
Basin during operations but not yet sold at December 31, 2009. Inventories are carried at the lower of cost or market
using the specific identification method. Crude oil was valued at
Brigham's estimated production cost of $136,000 at December 31,
2009.
Property and Equipment
Brigham uses the full cost method of accounting for oil and natural gas properties. Under this
method, all acquisition, exploration and development costs, including certain payroll, asset
retirement costs, other internal costs, and interest incurred for the purpose of finding oil and
natural gas reserves, are capitalized. Internal costs that are capitalized are directly
attributable to acquisition, exploration and development activities and do not include costs
related to production, general corporate overhead or similar activities. Costs associated with
production and general corporate activities are expensed in the period incurred. Proceeds from the
sale of oil and natural gas properties are applied to reduce the capitalized costs of oil and
natural gas properties unless the sale would significantly alter the relationship between
capitalized costs and proved reserves, in which case a gain or loss is recognized.
Capitalized costs associated with impaired properties and capitalized costs related to
properties having proved reserves, plus the estimated future development costs, and asset
retirement costs under Financial Accounting Standards Board Accounting Standards Codification Topic
410 Asset Retirement and Environmental Obligations (FASB ASC 410), are amortized using the
unit-of-production method based on proved reserves. Capitalized costs of oil and natural gas
properties, net of accumulated amortization and deferred income taxes, are limited to the total of
estimated future net cash flows from proved oil and natural gas reserves, discounted at ten
percent, plus the cost of unevaluated properties. The estimated future net cash flows for at
December 31, 2008 were determined using prices at the end of the year. Under certain specific
conditions, companies could elect to use subsequent prices for determining the estimated future net
cash flows. Brigham elected to use subsequent pricing for this purpose during 2007 and 2008. Under
new rules issued by the Securities and Exchange Commission, the estimated future net cash flows for
at December 31, 2009 were determined using a 12-month average price. The average is calculated using the first
day of the month price for each of the 12 months that make up the reporting period. The use of subsequent pricing
is no longer allowed. See New Pronouncements below for additional detail regarding
the new rules. There are many factors, including global events that may influence the production,
processing, marketing and price of oil and natural gas. A reduction in the valuation of oil and
natural gas properties resulting from declining prices or production could adversely impact
depletion rates and capitalized cost limitations. Capitalized costs associated with properties that
have not been evaluated through drilling or seismic analysis, including exploration wells in
progress at December 31, 2009, are excluded from the unit-of-production amortization. Exclusions are
adjusted annually based on drilling results and interpretative analysis.
Other property and equipment, which primarily consists of 3-D seismic interpretation
workstations, is depreciated on a straight-line basis over the estimated useful lives of the assets
after considering salvage value. Estimated useful lives are as follows:
|
|
|
|
|
Furniture and fixtures |
|
10 years |
Machinery and equipment |
|
5 years |
3-D seismic interpretation workstations and software |
|
3 years |
Pipeyard equipment |
|
7 years |
Pipeyard improvements |
|
15 years |
Rental equipment |
|
3 - 5 years |
Land |
|
|
|
|
Betterments and major improvements that extend the useful lives are capitalized while
expenditures for repairs and maintenance of a minor nature are expensed as incurred.
F-9
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Asset Retirement Obligations
Brigham records the fair value of a liability for an asset retirement obligation in the period
in which it is incurred and a corresponding increase in the carrying amount of the related
long-lived asset. The liability is accreted to its present value each period, and the capitalized
cost is depreciated over the useful life of the related asset. If the liability is settled for an
amount other than the recorded amount, a gain or loss is recognized.
Revenue Recognition
Brigham recognizes revenues from the sale of crude oil using the sales method of accounting.
Under this method, Brigham recognizes revenues when oil is delivered and title transfers.
Brigham recognizes revenues from the sale of natural gas using the entitlements method of
accounting. Under this method, revenues are recognized based on Brighams entitled ownership
percentage of sales of natural gas to purchasers. Gas imbalances occur when Brigham sells more or
less than its entitled ownership percentage of total natural gas production. When Brigham receives
less than its entitled share, a receivable is recorded. When Brigham receives more than its
entitled share, a liability is recorded.
Derivative Instruments and Hedging Activities
Brigham accounts for its derivative activities under Financial Accounting Standards Board
Accounting Standards Codification Topic 815 Derivatives and Hedging (FASB ASC 815). FASB ASC 815
establishes accounting and reporting standards requiring that every derivative instrument be
recorded on the balance sheet as either an asset or a liability measured at its fair value. The
statement requires that changes in the derivatives fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Brigham uses derivative instruments to manage
market risks resulting from fluctuations in the prices of crude oil and natural gas. Brigham
periodically enters into derivative contracts, including price swaps, caps and floors, which
require payments to (or receipts from) counterparties based on the differential between a fixed
price and a variable price for a fixed quantity of oil or natural gas without the exchange of
underlying volumes. The notional amounts of these financial instruments are based on expected
production from existing wells.
At the inception of a derivative contract, Brigham historically designated the derivative as a
cash flow hedge. Derivatives were recorded on the balance sheet at fair value and changes in the
fair value of derivatives were recorded each period in net income or other comprehensive income,
depending on whether a derivative was designated as part of a hedge transaction and, if it was,
depending on the type of hedge transaction. On October 1, 2006, Brigham de-designated all
derivates that were previously classified as cash flow hedges and, in addition, Brigham elected not
to designate any additional derivative contracts as accounting hedges under FASB ASC Topic 815. As
such, all derivative positions are carried at their fair value on the consolidated balance sheet
and are marked-to-market at the end of each period. Any realized and unrealized gains or losses are
recorded as gain (loss) on derivatives, net, as an increase or decrease in revenue on the
consolidated statement of operations rather than as a component of other comprehensive income or
other income (expense).
Other Comprehensive Income (Loss)
Brigham follows the provisions of Financial Accounting Standards Board Accounting Standards
Codification Topic 220 Comprehensive Income (FASB ASC 220), which establishes standards for
reporting comprehensive income. In addition to net income (loss), comprehensive income (loss)
includes all changes in equity during a period, except those resulting from investments and
distributions to stockholders of Brigham.
F-10
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table reflects the components of other comprehensive income (loss) for the years
ended December 31, 2009, 2008 and 2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Balance, beginning of year |
|
$ |
|
|
|
$ |
115 |
|
|
$ |
1,006 |
|
Unrealized (gains) losses on investments |
|
|
(205 |
) |
|
|
|
|
|
|
|
|
Tax benefits (provisions) related to cash flow hedges |
|
|
|
|
|
|
61 |
|
|
|
480 |
|
Net (gains) losses included in earnings |
|
|
|
|
|
|
(176 |
) |
|
|
(1,371 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
$ |
(205 |
) |
|
$ |
|
|
|
$ |
115 |
|
|
|
|
|
|
|
|
|
|
|
Stock Based Compensation
Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic
718 Compensation Stock Compensation (FASB ASC 718) to account for stock based compensation. See
Note 13, Stock Based Compensation, for a full discussion of our stock-based compensation.
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 of deferred tax assets and liabilities is
recognized in income in the year of the enacted rate change. Deferred tax assets are reduced by a
valuation allowance when, in the opinion of management, it is more likely than not that some
portion or all of the deferred tax assets will not be realized.
Deferred Loan Fees
Deferred loan fees incurred in connection with the issuance of debt are recorded on the
balance sheet in other noncurrent assets. The debt issue costs are amortized to interest expense
over the life of the debt using the straight-line method. The results obtained using the
straight-line method are not materially different than those that would result from using the
effective interest method.
Segment Information
All of Brighams oil and natural gas properties and related operations are located onshore in
the United States and management has determined that Brigham has one reportable segment.
Treasury Stock
Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares
held is reduced by the average purchase price per share of the aggregate treasury shares held.
Mandatorily Redeemable Preferred Stock
The Series A Preferred Stock is presented in accordance with Financial Accounting Standards
Board Accounting Standards Codification Topic 480 Distinguishing Liabilities from Equity (FASB
ASC 480). FASB ASC 480 requires an issuer to classify certain financial instruments within its
scope, such as mandatorily redeemable preferred stock, as liabilities (or assets in some
circumstances). FASB ASC 480 defines a financial instrument as mandatorily redeemable if it
embodies an unconditional obligation requiring the issuer to redeem the instrument by transferring
its assets at a specified or determinable date(s) or upon an event certain to occur.
F-11
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
New Pronouncements
In September 2006, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards Board Auditing Standard Codification Topic 820 Fair Value Measurements and
Disclosures (FASB ASC 820), which provides expanded guidance for using fair value to measure
assets and liabilities. FASB ASC 820 establishes a hierarchy for data used to value assets and
liabilities, and requires additional disclosures about the extent to which a company measures
assets and liabilities at fair value, the information used to measure fair value, and the effect of
fair value measurements on earnings. Implementation of FASB ASC 820 was required on January 1, 2008
for financial assets and liabilities, as well as other assets and liabilities that are carried at
fair value on a recurring basis in financial statements. The FASB Staff deferred implementation for
other non-financial assets and liabilities for one year. Examples of non-financial assets and
liabilities are asset retirement obligations and non-financial assets and liabilities initially
measured at fair value in a business combination. The adoption of FASB ASC 820 on January 1, 2009 did not have a
material impact on the financial statements.
On December 31, 2008, the SEC published the final rules and interpretations updating its oil
and gas reporting requirements. Many of the revisions are updates to definitions in the existing
oil and gas rules to make them consistent with the petroleum resource management system, which is a
widely accepted standard for the management of petroleum resources that was developed by several
industry organizations. Key revisions include the ability to include nontraditional resources in
reserves, the use of new technology for determining reserves, permitting disclosure of probable and
possible reserves, and changes to the pricing used to determine reserves in that companies must use
a 12-month average price. The average is calculated using the first-day-of-the-month price for each
of the 12 months that make up the reporting period. The SEC will require companies to comply with
the amended disclosure requirements for registration statements filed after January 1, 2010, and
for annual reports for fiscal years ending on or after December 15, 2009. Early adoption was not
permitted. Financial Accounting Standards Board Accounting Standards Codification Topic 932
Extractive Activities Oil and Gas (FASB ASC 932) provides guidance for oil and natural gas
reserve related disclosures in the financial statements. Adoption of the new requirements did not
have a material impact on Brighams financial statements.
In May 2009, the Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 165 Subsequent Events (SFAS 165). SFAS 165 establishes general
standards of accounting for and disclosure of events that occur after the balance sheet date but
before financial statements are issued or are available to be issued. SFAS 165 will apply with
respect to interim or annual reporting periods ending after June 15, 2009. See Note 16 Subsequent
Events.
In June 2009, the Financial Accounting Standards Board issued Financial Accounting Standards
Board Accounting Standards Codification Topic 105 Generally Accepted Accounting Principles (FASB
ASC 105). FASB ASC 105 sets forth that the Financial Accounting Standards Board Accounting
Standards Codification (ASC) is the exclusive authoritative reference for nongovernmental U.S. GAAP
for use in financial statements issued for interim and annual periods ending after September 15,
2009, except for SEC rules and interpretive releases, which also are authoritative GAAP for SEC
registrants. The change was established by FASB Statement of Financial Accounting Standards No.
168 The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting
Principles (FAS 168), which divides nongovernmental U.S. GAAP into the authoritative Codification
and guidance that is nonauthoritative, doing away with the previous four-level hierarchy. FASB ASC
105 is effective for financial statements for interim or annual reporting periods ending after
September 15, 2009. FASB ASC 105 was not intended to change or alter existing GAAP, and the
Companys adoption did not have any impact on its consolidated financial statements other than to
modify certain existing disclosures. Upon adoption, the Company began to use the new guidelines
and numbering system prescribed by the FASB ASC when referring to GAAP in the third quarter of
fiscal 2009.
3. Property and Equipment
Property and equipment, at cost, are summarized as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Oil and natural gas properties |
|
$ |
696,229 |
|
|
$ |
738,281 |
|
Accumulated depletion |
|
|
(365,496 |
) |
|
|
(333,442 |
) |
|
|
|
|
|
|
|
|
|
|
330,733 |
|
|
|
404,839 |
|
F-12
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Other property and equipment: |
|
|
|
|
|
|
|
|
3-D seismic interpretation workstations and software |
|
|
1,619 |
|
|
|
1,585 |
|
Office furniture and equipment |
|
|
3,307 |
|
|
|
3,438 |
|
Pipeyard equipment |
|
|
832 |
|
|
|
546 |
|
Rental equipment |
|
|
1,739 |
|
|
|
|
|
Land |
|
|
409 |
|
|
|
408 |
|
Accumulated depreciation |
|
|
(4,881 |
) |
|
|
(4,104 |
) |
|
|
|
|
|
|
|
|
|
|
3,025 |
|
|
|
1,873 |
|
|
|
|
|
|
|
|
|
|
$ |
333,758 |
|
|
$ |
406,712 |
|
|
|
|
|
|
|
|
Depletion expense is based on units-of-production. Production volumes used to determine
depletion expense were 1,796 MBoe, 1,910 MBoe, and 2,496 MBoe for 2009, 2008, and 2007
respectively. The depletion rate used to calculate depletion expense was $17.88, $28.02, and $23.64 for 2009, 2008, and 2007, respectively.
Brigham capitalizes certain payroll and other internal costs directly attributable to
acquisition, exploration and development activities as part of its investment in oil and natural
gas properties over the periods benefited by these activities. Capitalized costs do not include any
costs related to production, general corporate overhead, or similar activities. Capitalized costs
are summarized as follows for the years ended December 31, 2009, 2008 and 2007 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Capitalized certain payroll and other internal costs |
|
$ |
7,718 |
|
|
$ |
7,994 |
|
|
$ |
8,164 |
|
Capitalized interest costs |
|
|
4,713 |
|
|
|
4,761 |
|
|
|
3,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
12,431 |
|
|
$ |
12,755 |
|
|
$ |
11,631 |
|
|
|
|
|
|
|
|
|
|
|
The risk that Brigham will experience a ceiling test writedown increases when oil and gas
prices are depressed or if Brigham has substantial downward revisions in its estimated proved
reserves. Based on oil and natural gas prices in effect at the end of the second quarter 2007, the
unamortized cost of Brighams oil and gas properties exceeded the ceiling limit and Brigham was
required to record a writedown of its oil and gas properties in the amount of $4.1 million, net of
tax.
Based on oil and natural gas prices in effect at the end of the third quarter 2007, the
unamortized cost of Brighams oil and gas properties exceeded the ceiling limit by $13.5 million,
net of tax. However, subsequent to the end of the quarter, oil and natural gas prices increased
and, utilizing these prices, Brighams net capitalized costs of oil and natural gas properties
would not have exceeded the ceiling limit. As a result of the increase in the ceiling limit using
subsequent prices, Brigham was not required to writedown the net capitalized costs of its oil and
gas properties.
Based on oil and gas prices in effect at the end of December 2008 ($5.710 per MMBtu for Henry
Hub natural gas and $44.60 per barrel for West Texas Intermediate oil, adjusted for differentials),
the unamortized cost of Brighams oil and gas properties exceeded the ceiling limit by $148.6
million, net of tax. As a result, Brigham was required to record a writedown of the net
capitalized costs of its oil and gas properties in the amount of $237.2 million at
December 31, 2008.
Based on oil and gas prices in effect at the end of March 2009 ($3.63 per MMBtu for Henry Hub
gas and $49.65 per barrel for West Texas Intermediate oil, adjusted for differentials), the
unamortized cost of Brighams oil and gas properties exceeded the ceiling limit by $71.9 million,
net of tax. As a result, Brigham was required to record a writedown of the net capitalized costs
of its oil and gas properties in the amount of $114.8 million at March 31, 2009.
Based on average oil and gas prices for the year ended December 31, 2009 ($3.87 per MMBtu for
Henry Hub natural gas and $61.18 per barrel for West Texas Intermediate oil, adjusted for
differentials), the unamortized cost of Brighams oil and gas properties did not exceed the ceiling
limit. Therefore, Brigham was not required to writedown the net capitalized costs of its oil and
gas properties at December 31, 2009.
F-13
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. Common Stock
In May 2009, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 36,292,117 shares of its common stock at a price of $2.75 and
received net proceeds of $93.4 million after underwriting fees and offering expenses.
In October 2009, the stockholders approved an amendment to Brighams Certificate of
Incorporation to increase the number of shares of common stock which Brigham is authorized to issue
from 90 million shares to 180 million shares. The amendment to the Certificate of Incorporation
became effective on October 7, 2009. Additionally, stockholders approved an amendment to the 1997
Incentive Plan that increased the number of shares of common stock available for issuance under the
1997 Incentive Plan to the lesser of (i) 9,966,603 or (ii) 12% of the total number of shares of
common stock outstanding at any time.
In October 2009, Brigham completed a public offering of common stock pursuant to a shelf
registration statement. Brigham sold 16,000,000 shares of its common stock at a price of $10.50
and received net proceeds of $159.9 million after underwriting fees and offering expenses.
In November 2009, the Underwriters elected to exercise a portion of the over-allotment option
associated with the October 2009 equity offering. This resulted in the issuance of 837,523
additional shares of common stock and Brigham received net proceeds of $8.4 million after
underwriting fees and offering expenses.
5. Senior Credit Facility, Senior Notes, and Senior Subordinated Notes
The following table reflects the outstanding balances of the
senior credit facility and senior
notes for the years ended December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Senior Credit Facility |
|
$ |
|
|
|
$ |
145,000 |
|
Senior Notes |
|
|
160,000 |
|
|
|
160,000 |
|
Discount on Senior Notes |
|
|
(1,032 |
) |
|
|
(1,270 |
) |
|
|
|
|
|
|
|
Total Debt |
|
$ |
158,968 |
|
|
$ |
303,730 |
|
Less: Current Maturities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Long-Term Debt |
|
$ |
158,968 |
|
|
$ |
303,730 |
|
|
|
|
|
|
|
|
F-14
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Senior Credit Facility
In November 2008, in conjunction with Brighams regularly scheduled semi-annual
redetermination, the borrowing base was reset to $145 million. In May 2009, in conjunction with
Brighams regularly scheduled semi-annual redetermination, the borrowing base was reset to $110
million. Brigham used proceeds from the May stock
offering to repay $35 million of outstanding borrowings under its Senior Credit Facility. On
July 24, 2009, Brigham amended and restated the Senior Credit Facility to extend the maturity of
the agreement from June 2010 to July 2012. During October 2009, Brigham used a portion of the
proceeds from the October stock offering to repay borrowings under the Senior Credit Facility of $110
million.
Borrowings under the Senior Credit Facility bear interest, at Brighams election, at a base
rate (as the term is defined in the Senior Credit Facility) or Eurodollar rate, plus in each case
an applicable margin that is reset quarterly (2.5% at December 31, 2009). The applicable interest
rate margin varies from 1.5% to 2.5% in the case of borrowings based on the base rate (as the term
is defined in the Senior Credit Facility) and from 2.5% to 3.5% in the case of borrowings based on
the Eurodollar rate, depending on percentage of the available borrowing base utilized. In
addition, Brigham is required to pay a commitment fee on the unused portion of its borrowing base
(0.50% at December 31, 2009). Borrowings under the Senior Credit Facility are collateralized by
substantially all of Brighams oil and natural gas properties under first liens.
The Senior Credit Facility contains various covenants, including among others restrictions on
liens, restrictions on incurring other indebtedness, restrictions on mergers, restrictions on
investments, and restrictions on hedging activity of a speculative nature or with counterparties
having credit ratings below specified levels. The Senior Credit Facility requires Brigham to
maintain a current ratio (as defined) of at least 1 to 1. The Senior Credit Facility also requires
Brigham to maintain an interest coverage ratio for the quarters ending December 31, 2009 and March
31, 2010 of at least 2.0 to 1, and thereafter must be at least 2.5 to 1. The Senior Credit
Facility also requires Brigham to maintain a net leverage ratio for the quarters ending December
31, 2009 through September 30, 2010 not greater than 4.5 to 1, for the quarters ending December 31,
2010 and March 31, 2011 not greater than 4.25 to 1, and thereafter not greater than 4.0 to 1. At
December 31, 2009, Brigham was in compliance with all covenants under the Senior Credit Facility.
Senior Notes
In April 2006, Brigham issued $125 million of 9 5/8% Senior Notes due in 2014 (the Senior
Notes). The Senior Notes were priced at 98.629% of their face value to yield 9 7/8% and are fully
and unconditionally guaranteed by Brigham and its wholly-owned subsidiaries, Brigham, Inc. and
Brigham Oil & Gas, L.P. The guarantees are joint and several. Brigham does not have any independent
assets or operations.
In April 2007, Brigham issued $35 million of 9 5/8% Senior Notes due 2014. The notes were
issued as an add-on to the existing $125 million of 9 5/8% Senior Notes due 2014 under the
indenture dated April 20, 2006. The add-on notes were priced at 99.50% of face value to yield
9.721%. Upon completion of the add-on, Brigham had outstanding $160 million in 9 5/8% Senior Notes
due 2014 (collectively the Senior Notes).
The indenture contains various covenants, including among others restrictions on incurring
other indebtedness, restrictions on liens, restrictions on the sale of assets, and restrictions on
certain payments. To issue new debt, the indenture requires Brigham to maintain a fixed charge
coverage ratio (as defined) for the most recent four full fiscal quarters of at least 2.5 to 1. At
December 31, 2009, Brigham was in compliance with all covenants under the indenture.
6. Preferred Stock
Series A Mandatorily Redeemable Preferred Stock
The following table reflects the outstanding shares of Series A mandatorily redeemable
preferred stock and the activity related thereto for the years ended December 31, 2009 and 2008 (in
thousands, except share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
Year Ended |
|
|
|
December 31, 2009 |
|
|
December 31, 2008 | |
|
|
Shares |
|
|
Amounts |
|
|
Shares |
|
|
Amounts |
|
Balance, beginning of year |
|
|
505,051 |
|
|
$ |
10,101 |
|
|
|
505,051 |
|
|
$ |
10,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, end of year |
|
|
505,051 |
|
|
$ |
10,101 |
|
|
|
505,051 |
|
|
$ |
10,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-15
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Brigham has designated 2,250,000 shares of preferred stock as Series A Preferred Stock. The
Series A Preferred Stock has a par value of $0.01 per share and a stated value of $20 per share.
The Series A Preferred Stock is cumulative and pays dividends quarterly at a rate of 6% per annum
of the stated value in cash. The Series A Preferred Stock matures on October 31, 2010 and is
redeemable at Brighams option at 100% or 101% of stated value (depending upon certain conditions)
at anytime prior to maturity. The Series A Preferred Stock does not generally have any voting
rights, except for certain approval rights and as required by law.
7. Asset Retirement Obligations
Brigham has asset retirement obligations associated with the future plugging and abandonment
of proved properties and related facilities. Prior to the adoption of Financial Accounting
Standards Board Accounting Standards Codification Topic 410 Asset Retirement and Environmental
Obligations (FASB ASC 410), Brigham assumed salvage value approximated plugging and abandonment
costs. As such, estimated salvage value was not excluded from depletion and plugging and
abandonment costs were not accrued for over the life of the oil and gas properties. Under the
provisions of FASB ASC 410, the fair value of a liability for an asset retirement obligation is
recorded in the period in which it is incurred and a corresponding increase in the carrying amount
of the related long-lived asset. The liability is accreted to its present value each period, and
the capitalized cost is depreciated over the useful life of the related asset. If the liability is
settled for an amount other than the recorded amount, a gain or loss is recognized. Brigham has no
assets that are legally restricted for purposes of settling asset retirement obligations.
The following table summarizes Brighams asset retirement obligation transactions
recorded in accordance with the provisions of SFAS 143 during the years ended December 31, 2009 and
2008 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Beginning asset retirement obligations |
|
$ |
5,592 |
|
|
$ |
5,047 |
|
Liabilities incurred for new wells placed on production |
|
|
327 |
|
|
|
412 |
|
Liabilities settled |
|
|
(17 |
) |
|
|
(228 |
) |
Revisions to estimates due to sale of oil and gas properties |
|
|
|
|
|
|
|
|
Accretion of discount on asset retirement obligations |
|
|
421 |
|
|
|
361 |
|
|
|
|
|
|
|
|
|
|
$ |
6,323 |
|
|
$ |
5,592 |
|
|
|
|
|
|
|
|
8. Income Taxes
Brigham utilizes the
asset and liability approach to measure deferred tax assets and
liabilities based on temporary differences existing at each balance sheet date using currently
enacted tax rates in accordance with Financial Accounting Standards Board Accounting Standards
Codification Topic 740 Income Taxes (FASB ASC 740). Deferred tax assets and liabilities are
adjusted for the effects of changes in tax laws and rates on the date of enactment. Under FASB ASC
740, deferred tax assets are reduced by a valuation allowance when, in the opinion of management,
it is more likely than not that some portion or all of the deferred tax assets will not be
realized. During 2009, Brighams deferred tax asset relating to oil and gas properties was
increased primarily due to Brighams ceiling test writedown in the first quarter of 2009. After testing to determine if
the deferred tax assets would meet the more likely than not criteria, Brigham increased its federal
valuation allowance to $77.1 million and its state valuation allowance to $5.9 million.
F-16
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The total provision for income taxes consists of the following (dollar amounts are in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Current income taxes |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Deferred income taxes (benefits): |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
(43,029 |
) |
|
|
(71,445 |
) |
|
|
5,827 |
|
State |
|
|
(1,141 |
) |
|
|
(5,745 |
) |
|
|
901 |
|
Valuation allowances |
|
|
43,937 |
|
|
|
34,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(233 |
) |
|
$ |
(42,701 |
) |
|
$ |
6,728 |
|
|
|
|
|
|
|
|
|
|
|
The provision for income taxes differs from the amount computed by applying the statutory
federal income tax rate to net income before taxes. The sources of the tax effects of the
differences are as follows (dollar amounts are in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Tax (benefit) at statutory rate |
|
$ |
(43,129 |
) |
|
$ |
(71,732 |
) |
|
$ |
5,929 |
|
Add the effect of: |
|
|
|
|
|
|
|
|
|
|
|
|
Nondeductible expenses, net of tax exempt income |
|
|
1 |
|
|
|
6 |
|
|
|
6 |
|
Preferred stock dividends |
|
|
212 |
|
|
|
212 |
|
|
|
212 |
|
Incentive stock options not exercised |
|
|
26 |
|
|
|
47 |
|
|
|
34 |
|
State income taxes (benefits), net of federal deduction |
|
|
(741 |
) |
|
|
(3,734 |
) |
|
|
586 |
|
State valuation allowance, net of federal deduction |
|
|
644 |
|
|
|
2,455 |
|
|
|
|
|
Federal valuation allowance |
|
|
42,719 |
|
|
|
30,002 |
|
|
|
(61 |
) |
Other |
|
|
35 |
|
|
|
43 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(233 |
) |
|
$ |
(42,701 |
) |
|
$ |
6,728 |
|
|
|
|
|
|
|
|
|
|
|
The components of deferred income tax assets and liabilities are as follows (dollar amounts
are in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Deferred tax assets |
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
Unrealized hedging and other derivative losses |
|
$ |
913 |
|
|
$ |
2 |
|
State deferred taxes |
|
|
|
|
|
|
52 |
|
Other |
|
|
36 |
|
|
|
42 |
|
|
|
|
|
|
|
|
Current |
|
|
949 |
|
|
|
96 |
|
|
|
|
|
|
|
|
Non-current: |
|
|
|
|
|
|
|
|
Net operating loss carryforwards (NOLs) |
|
|
84,706 |
|
|
|
75,956 |
|
Percentage depletion carryforwards |
|
|
4,433 |
|
|
|
4,201 |
|
Stock compensation |
|
|
3,328 |
|
|
|
2,786 |
|
Asset retirement obligations |
|
|
2,213 |
|
|
|
1,957 |
|
Unrealized derivative losses |
|
|
318 |
|
|
|
|
|
Other |
|
|
81 |
|
|
|
73 |
|
|
|
|
|
|
|
|
F-17
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
Non-current |
|
|
95,079 |
|
|
|
84,973 |
|
|
|
|
|
|
|
|
|
|
|
96,028 |
|
|
|
85,069 |
|
Valuation allowance |
|
|
(77,153 |
) |
|
|
(34,202 |
) |
|
|
|
|
|
|
|
Total net deferred tax assets |
|
|
18,875 |
|
|
|
50,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities |
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
Unrealized derivative gains |
|
$ |
(403 |
) |
|
$ |
(1,799 |
) |
|
|
|
|
|
|
|
Current |
|
|
(403 |
) |
|
|
(1,799 |
) |
|
|
|
|
|
|
|
Non-current: |
|
|
|
|
|
|
|
|
Depreciable and depletable property |
|
|
(18,392 |
) |
|
|
(48,983 |
) |
Other |
|
|
(80 |
) |
|
|
(85 |
) |
|
|
|
|
|
|
|
Non-current |
|
|
(18,472 |
) |
|
|
(49,068 |
) |
|
|
|
|
|
|
|
Total net deferred tax liabilities |
|
|
(18,875 |
) |
|
|
(50,867 |
) |
|
|
|
|
|
|
|
Total federal deferred tax asset (liability) |
|
|
|
|
|
|
|
|
Total state deferred tax asset (liability) |
|
|
|
|
|
|
(149 |
) |
|
|
|
|
|
|
|
Total deferred tax asset (liability) |
|
$ |
|
|
|
$ |
(149 |
) |
|
|
|
|
|
|
|
At December 31, 2009, Brigham has regular U. S. Federal tax NOLs of approximately $248 million
available as a deduction against future taxable income. Additionally, Brigham has approximately
$233 million of U. S. Federal alternative minimum tax (AMT) NOLs. The NOLs expire from 2012
through 2029. The value of these NOLs depends on the ability of Brigham to generate taxable income.
Brigham also has U. S. State tax NOLs of approximately $80 million and a Texas Franchise tax
credit carryover of approximately $1.4 million. The increases in the valuation allowances have no
impact on Brighams NOL positions for federal and state tax purposes.
Brigham believes an Internal Revenue Code Sec. 382 ownership change may have occurred in March
2001 and in November 2005, as a result of a potential 50% change in ownership among its 5%
shareholders over a three-year period. Limitations on the utilization of Brighams NOLs may result
from the March 2001 and November 2005 ownership changes. The limitations approximate $5.2 million
annually and $22 million annually, respectively.
On January 1, 2007, Brigham adopted additional provisions under FASB ASC 740, which provides
that the tax effects from an uncertain tax position can be recognized in the financial statements
only if the position is more likely than not of being sustained if the position were to be
challenged by a taxing authority. In 2006 and 2007, Brigham examined the tax positions taken in
its tax returns and determined that the full values of the uncertain tax positions were reflected
as part of its deferred tax liabilities and reclassified these liabilities to other tax liabilities
on the consolidated balance sheet. In 2008, Brigham received approval from the Internal Revenue
Service to change its method of accounting for certain geological and geophysical costs and no
longer has a liability for uncertain tax positions. As a result, as of December 31, 2008, Brigham
eliminated the other tax liabilities in its consolidated balance sheet.
The following table sets forth the reconciliation of unrecognized tax benefits:
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Unrecognized tax benefits at beginning of the year |
|
$ |
|
|
|
$ |
2,162 |
|
Increases (decreases) resulting from adoption |
|
|
|
|
|
|
|
|
Increases (decreases) resulting from tax positions taken in the current period |
|
|
|
|
|
|
(2,162 |
) |
|
|
|
|
|
|
|
Unrecognized tax benefits at end of the year |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
F-18
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The tax years that remain subject to examination by Federal and major state tax jurisdictions
are the years ended December 31, 2009, 2008, 2007, and 2006. In addition, Brigham is open to
examination for the years 1997 through 2005, resulting from NOLs generated and available for
carryforward.
9. Net Income Available Per Common Share
Basic earnings per share are computed by dividing net income (loss) available to common
stockholders by the weighted average number of common shares outstanding for the period. Diluted
EPS is computed by dividing net income by the weighted average number of common shares and
potential common shares outstanding (if dilutive) during each period. Potential common shares
include stock options and restricted stock. The number of potential common shares outstanding
relating to stock options and restricted stock is computed using the treasury stock method.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
(In thousands, except per share amounts) |
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
$ |
10,210 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding basic |
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,110 |
|
|
|
|
|
|
|
|
|
|
|
Basic EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
$ |
0.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders diluted |
|
$ |
(122,992 |
) |
|
$ |
(162,247 |
) |
|
$ |
10,210 |
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding |
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,110 |
|
Effect of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and restricted stock |
|
|
|
|
|
|
|
|
|
|
421 |
|
|
|
|
|
|
|
|
|
|
|
Potentially dilutive common shares |
|
|
|
|
|
|
|
|
|
|
421 |
|
|
|
|
|
|
|
|
|
|
|
Adjusted common shares outstanding diluted |
|
|
70,569 |
|
|
|
45,441 |
|
|
|
45,531 |
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS: |
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) available to common stockholders |
|
$ |
(1.74 |
) |
|
$ |
(3.57 |
) |
|
$ |
0.22 |
|
|
|
|
|
|
|
|
|
|
|
At December 31, 2009, 2008, and 2007, potential dilution of approximately 4.7 million, 3.7
million, and 2.8 million shares of common stock, respectively, related to mandatorily redeemable
preferred stock and options were outstanding, but were not included in the computation of diluted
income (loss) per share because the effect of these instruments would have been anti-dilutive.
10. Contingencies, Commitments and Factors Which May Affect Future Operations
Litigation
Brigham is, from time to time, party to certain lawsuits and claims arising in the ordinary
course of business. While the outcome of lawsuits and claims cannot be predicted with certainty,
management does not expect these matters to have a materially adverse effect on the financial
condition, results of operations or cash flows of Brigham.
As of December 31, 2009, there are no known environmental or other regulatory matters related
to Brighams operations that are reasonably expected to result in a material liability to Brigham.
Compliance with environmental laws and regulations has not had, and is not expected to have, a
material adverse effect on Brighams financial position, results of operations or cash flows.
F-19
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Operating Lease Commitments
Brigham leases office equipment and space under operating leases expiring at various dates.
The noncancelable term of the leases for Brighams office space expires in 2012. Brigham is also
subject to early termination fees for four drilling rigs under a contract that is
quarter-to-quarter through May 2011. The future minimum annual rental payments under the
noncancelable terms of these leases and potential fees for early termination of the drilling rig
contract at December 31, 2009 are as follows (in thousands):
|
|
|
|
|
2010 |
|
|
1,521 |
|
2011 |
|
|
738 |
|
2012 |
|
|
378 |
|
|
|
|
|
|
|
$ |
2,637 |
|
|
|
|
|
Rental expense for the years ended December 31, 2009, 2008 and 2007 was approximately
$804,000, $770,000, and $801,000, respectively.
Major Purchasers
The following purchasers accounted for 10% or more of Brighams oil and natural gas sales for
the years ended December 31, 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Purchaser A |
|
|
|
|
|
|
|
|
|
|
13 |
% |
Purchaser B |
|
|
|
|
|
|
21 |
% |
|
|
27 |
% |
Purchaser C |
|
|
|
|
|
|
|
|
|
|
13 |
% |
Purchaser D |
|
|
31 |
% |
|
|
19 |
% |
|
|
11 |
% |
Purchaser E |
|
|
13 |
% |
|
|
|
|
|
|
|
|
Brigham believes that the loss of any individual purchaser would not have a long-term material
adverse impact on its financial position or results of operations.
Factors Which May Affect Future Operations
Since Brighams major products are commodities, significant changes in the prices of oil and
natural gas could have a significant impact on Brighams results of operations for any particular
year.
11. Derivative Instruments and Hedging Activities
Brigham utilizes various commodity swap and option contracts to (i) reduce the effects of
volatility in price changes on the oil and natural gas commodities it produces and sells, (ii)
reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can
execute at least a portion of its capital spending plans.
Natural
Gas and Crude Oil Derivative Contracts
Cash flow hedges
Brigham enters into contracts to hedge against the variability in cash flows associated with
the forecasted sale of future oil and gas production. Brighams hedges consist of swaps, costless
collars (purchased put options and written call options), and three-way collars (a standard collar
plus a sold put below the floor price of the collar). The costless collars and three-way collars
are used to establish floor and ceiling prices on anticipated future oil and natural gas
production. There are no net premiums paid or received when Brigham enters into these option
agreements. Brigham has elected not to designate any of its derivative contracts as cash flow
hedges for accounting purposes under Financial Accounting Standards Board Accounting Standards
Codification Topic 815 Derivatives and Hedging (FASB ASC 815). As such, all derivative positions
are carried at their fair value on the consolidated balance sheet and are marked-to-market at the
end of each period. See Note 12, Fair Values, for a discussion of the calculation of the fair
values of
oil and natural gas derivative contracts. Any realized and unrealized gains or losses are
recorded as gain (loss) on
derivatives, net, as an increase or decrease in revenue on the consolidated statement of
operations.
F-20
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables reflect Brighams open commodity derivative contracts at December 31,
2009, the associated volumes and the corresponding weighted average NYMEX reference price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
|
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMBTU) |
|
|
(Barrels) |
|
|
Nymex |
|
|
Nymex |
|
Natural Gas Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/10 03/31/10 |
|
|
210,000 |
|
|
|
|
|
|
$ |
5.75 |
|
|
$ |
7.05 |
|
01/01/10 12/31/10 |
|
|
840,000 |
|
|
|
|
|
|
$ |
5.15 |
|
|
$ |
7.00 |
|
04/01/10 09/30/10 |
|
|
420,000 |
|
|
|
|
|
|
$ |
5.75 |
|
|
$ |
7.30 |
|
04/01/10 09/30/10 |
|
|
240,000 |
|
|
|
|
|
|
$ |
5.75 |
|
|
$ |
7.00 |
|
04/01/10 09/30/10 |
|
|
300,000 |
|
|
|
|
|
|
$ |
5.50 |
|
|
$ |
6.65 |
|
10/01/10 03/31/11 |
|
|
240,000 |
|
|
|
|
|
|
$ |
6.50 |
|
|
$ |
8.25 |
|
10/01/10 03/31/11 |
|
|
420,000 |
|
|
|
|
|
|
$ |
6.40 |
|
|
$ |
7.80 |
|
01/01/11 12/31/11 |
|
|
360,000 |
|
|
|
|
|
|
$ |
5.75 |
|
|
$ |
7.65 |
|
Oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/10 03/31/10 |
|
|
|
|
|
|
9,000 |
|
|
$ |
60.00 |
|
|
$ |
91.75 |
|
01/01/10 05/31/10 |
|
|
|
|
|
|
50,000 |
|
|
$ |
57.50 |
|
|
$ |
75.95 |
|
01/01/10 03/31/10 |
|
|
|
|
|
|
6,000 |
|
|
$ |
65.00 |
|
|
$ |
87.50 |
|
01/01/10 12/31/10 |
|
|
|
|
|
|
120,000 |
|
|
$ |
48.70 |
|
|
$ |
80.00 |
|
01/01/10 12/31/10 |
|
|
|
|
|
|
54,000 |
|
|
$ |
60.00 |
|
|
$ |
86.50 |
|
01/01/10 12/31/10 |
|
|
|
|
|
|
60,000 |
|
|
$ |
60.00 |
|
|
$ |
88.80 |
|
04/01/10 09/30/10 |
|
|
|
|
|
|
18,000 |
|
|
$ |
60.00 |
|
|
$ |
91.40 |
|
06/01/10 12/31/10 |
|
|
|
|
|
|
56,000 |
|
|
$ |
57.50 |
|
|
$ |
82.15 |
|
07/01/10 09/30/10 |
|
|
|
|
|
|
6,000 |
|
|
$ |
70.00 |
|
|
$ |
87.25 |
|
10/01/10 12/31/10 |
|
|
|
|
|
|
3,000 |
|
|
$ |
70.00 |
|
|
$ |
88.50 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
84,000 |
|
|
$ |
65.00 |
|
|
$ |
88.25 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
60,000 |
|
|
$ |
60.00 |
|
|
$ |
97.25 |
|
01/01/10 06/30/10 |
|
|
|
|
|
|
30,000 |
|
|
$ |
60.00 |
|
|
$ |
103.75 |
|
01/01/10 12/31/10 |
|
|
|
|
|
|
24,000 |
|
|
$ |
60.00 |
|
|
$ |
100.00 |
|
01/01/10 12/31/10 |
|
|
|
|
|
|
36,000 |
|
|
$ |
60.00 |
|
|
$ |
96.00 |
|
01/01/11 06/30/11 |
|
|
|
|
|
|
18,000 |
|
|
$ |
65.00 |
|
|
$ |
97.50 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
60,000 |
|
|
$ |
65.00 |
|
|
$ |
108.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
Purchased |
|
|
Written |
|
|
Written |
|
|
|
Gas |
|
|
Put |
|
|
Call |
|
|
Put |
|
Settlement Period |
|
(MMBTU) |
|
|
Nymex |
|
|
Nymex |
|
|
Nymex |
|
Natural Gas Three Way
Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/10 03/31/10 |
|
|
210,000 |
|
|
$ |
8.00 |
|
|
$ |
10.00 |
|
|
$ |
5.50 |
|
01/01/10 03/31/10 |
|
|
180,000 |
|
|
$ |
5.75 |
|
|
$ |
7.00 |
|
|
$ |
3.50 |
|
F-21
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following tables reflect commodity derivative contracts entered subsequent to
December 31, 2009, the
associated volumes and the corresponding weighted average NYMEX reference price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
|
|
|
Purchased |
|
|
Written |
|
|
|
Gas |
|
|
Oil |
|
|
Put |
|
|
Call |
|
Settlement Period |
|
(MMBTU) |
|
|
(Barrels) |
|
|
Nymex |
|
|
Nymex |
|
Natural Gas Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
01/01/11 12/31/11 |
|
|
480,000 |
|
|
|
|
|
|
$ |
5.75 |
|
|
$ |
7.40 |
|
Oil Costless Collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
03/01/10 08/31/10 |
|
|
|
|
|
|
18,000 |
|
|
$ |
70.00 |
|
|
$ |
99.00 |
|
03/01/10 12/31/10 |
|
|
|
|
|
|
40,000 |
|
|
$ |
70.00 |
|
|
$ |
101.75 |
|
04/01/10 06/30/10 |
|
|
|
|
|
|
30,000 |
|
|
$ |
65.00 |
|
|
$ |
89.90 |
|
07/01/10 12/31/10 |
|
|
|
|
|
|
30,000 |
|
|
$ |
65.00 |
|
|
$ |
94.25 |
|
07/01/10 12/31/10 |
|
|
|
|
|
|
12,000 |
|
|
$ |
65.00 |
|
|
$ |
107.70 |
|
01/01/11 02/28/11 |
|
|
|
|
|
|
10,000 |
|
|
$ |
70.00 |
|
|
$ |
92.00 |
|
01/01/11 06/30/11 |
|
|
|
|
|
|
24,000 |
|
|
$ |
70.00 |
|
|
$ |
92.50 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
48,000 |
|
|
$ |
70.00 |
|
|
$ |
106.80 |
|
01/01/11 12/31/11 |
|
|
|
|
|
|
48,000 |
|
|
$ |
75.00 |
|
|
$ |
102.60 |
|
07/01/11 09/30/11 |
|
|
|
|
|
|
9,000 |
|
|
$ |
70.00 |
|
|
$ |
95.00 |
|
07/01/11 12/31/11 |
|
|
|
|
|
|
12,000 |
|
|
$ |
75.00 |
|
|
$ |
103.00 |
|
10/01/11 12/31/11 |
|
|
|
|
|
|
6,000 |
|
|
$ |
70.00 |
|
|
$ |
96.35 |
|
Additional Disclosures about Derivative Instruments and Hedging Activities
At December 31, 2009, Brigham had derivative financial instruments under FASB ASC 815 recorded
on the consolidated balance sheet as set forth below:
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
Type of Contract |
|
Balance Sheet Location |
|
Fair Value |
|
|
|
|
|
(in thousands) |
|
Derivatives Not Designated as Hedging Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Assets: |
|
|
|
|
|
|
Oil and natural gas contracts |
|
Derivative assets current |
|
$ |
1,152 |
|
Oil and natural gas contracts |
|
Other non-current assets |
|
|
186 |
|
|
|
|
|
|
|
Total Derivative Assets |
|
|
|
$ |
1,338 |
|
|
|
|
|
|
|
|
Derivative Liabilities: |
|
|
|
|
|
|
Oil and natural gas contracts |
|
Other current liabilities |
|
$ |
(2,404 |
) |
Oil and natural gas contracts |
|
Other non-current liabilities |
|
|
(909 |
) |
|
|
|
|
|
|
Total Derivative Liabilities |
|
|
|
$ |
(3,313 |
) |
For the twelve months ended December 31, 2009, the effect on income in the
consolidated statement of operations for derivative financial instruments under FASB ASC 815 was as
follows:
|
|
|
|
|
|
|
|
|
|
|
Twelve Months |
|
|
|
|
|
Ended Dec 31, |
|
|
|
Statement of Operations |
|
Amount of |
|
Type of Contract |
|
Location of Gain (Loss) |
|
Gain (Loss) |
|
|
|
|
|
(in thousands) |
|
Derivatives Not Designated as Hedging Instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas contracts |
|
Gain (loss) on derivatives, net |
|
$ |
7,061 |
|
Oil contracts |
|
Gain (loss) on derivatives, net |
|
|
(4,997 |
) |
|
|
|
|
|
|
Total Derivative Gain (loss) |
|
|
|
$ |
2,064 |
|
F-22
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The use of derivative transactions involves the risk that the counterparties will be unable to
meet the financial terms of such transactions. Brighams derivative contracts are with multiple
counterparties to minimize its exposure to any individual counterparty and Brigham has netting
arrangements with all of its counterparties that provide for offsetting payables against
receivables from separate derivative instruments with that counterparty.
12. Fair Values
Brigham adopted Financial Accounting Standards Board Accounting Standards Codification Topic
820 Fair Value Measurements and Disclosures (FASB ASC 820) on January 1, 2008, as it relates to
financial assets and liabilities. Brigham adopted FASB ASC 820 on January 1, 2009, as it relates
to nonfinancial assets and liabilities. FASB ASC 820 establishes a fair value hierarchy that
prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy
defined by FASB ASC 820 are as follows:
|
|
|
Level 1 Unadjusted quoted prices are available in active markets for identical assets
or liabilities. |
|
|
|
Level 2 Pricing inputs, other than quoted prices within Level 1, that are either
directly or indirectly observable. |
|
|
|
Level 3 Pricing inputs that are unobservable requiring the use of valuation
methodologies that result in managements best estimate of fair value. |
As such, effective January 1, 2008, the fair values of Brighams derivative financial
instruments reflect Brighams estimate of the default risk of the parties in accordance with FASB
ASC 820. Brigham determines the fair value of derivative financial instruments based on
counterparties valuation models that utilize market-corroborated inputs. The fair value of all
derivative contracts is reflected on the balance sheet as detailed in the following schedule. The
current asset and liability amounts represent the fair values expected to be included in the
results of operations for the subsequent year.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2009 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Other current liabilities |
|
$ |
(2,404 |
) |
|
$ |
|
|
|
$ |
(2,404 |
) |
|
$ |
|
|
Other non-current liabilities |
|
|
(909 |
) |
|
|
|
|
|
|
(909 |
) |
|
|
|
|
Current derivative assets |
|
|
1,152 |
|
|
|
|
|
|
|
1,152 |
|
|
|
|
|
Other non-current assets |
|
|
186 |
|
|
|
|
|
|
|
186 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,975 |
) |
|
$ |
|
|
|
$ |
(1,975 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2008 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2008 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Other current liabilities |
|
$ |
(5 |
) |
|
$ |
|
|
|
$ |
(5 |
) |
|
$ |
|
|
Other non-current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current derivative assets |
|
|
5,140 |
|
|
|
|
|
|
|
5,140 |
|
|
|
|
|
Other non-current assets |
|
|
202 |
|
|
|
|
|
|
|
202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5,337 |
|
|
$ |
|
|
|
$ |
5,337 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-23
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Brighams assessment of the significance of a particular input to the fair value measurement
requires judgment and may effect the valuation of the nonfinancial assets and liabilities and their
placement in the fair value hierarchy levels. The fair value of Brighams asset retirement
obligations are determined using discounted cash flow methodologies based on inputs that are not
readily available in public markets. The fair value of the asset retirement obligations is
reflected on the balance sheet as detailed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2009 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Other non-current liabilities |
|
|
(6,323 |
) |
|
|
|
|
|
|
|
|
|
|
(6,323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(6,323 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(6,323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2008 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2008 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Other non-current liabilities |
|
|
(5,592 |
) |
|
|
|
|
|
|
|
|
|
|
(5,592 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(5,592 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(5,592 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
See Note 7 for a rollforward of the asset retirement obligation.
As of December 31, 2009, Brigham held $80.1 million of investments in certificates of deposit,
corporate debt, and government securities. There were no investments at December 31, 2008. The
fair value of the investments is reflected on the balance sheet as detailed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009 Using |
|
|
|
|
|
|
|
Quoted Prices in |
|
|
Significant Other |
|
|
Significant |
|
|
|
|
|
|
|
Active Markets |
|
|
Observable |
|
|
Unobservable |
|
|
|
December 31, |
|
|
for Identical Assets |
|
|
Inputs |
|
|
Inputs |
|
Description |
|
2009 |
|
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
Investments |
|
|
80,093 |
|
|
|
80,093 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
80,093 |
|
|
$ |
80,093 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes, by major security type, the fair value and any unrealized gain
(loss) of Brighams investments. The unrealized gain (loss) is recorded on the consolidated
balance sheet as other comprehensive income (loss), a component of stockholders equity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less Than 12 Months |
|
|
12 Months or Greater |
|
|
Total |
|
|
|
|
|
|
|
Unrealized |
|
|
|
|
|
|
Unrealized |
|
|
|
|
|
|
Unrealized |
|
|
|
Fair |
|
|
Gains |
|
|
Fair |
|
|
Gains |
|
|
Fair |
|
|
Gains |
|
Description of Securities |
|
Value |
|
|
(Losses) |
|
|
Value |
|
|
(Losses) |
|
|
Value |
|
|
(Losses) |
|
Certificates of deposit |
|
$ |
8,877 |
|
|
$ |
(15 |
) |
|
$ |
239 |
|
|
$ |
(1 |
) |
|
$ |
9,116 |
|
|
$ |
(16 |
) |
Corporate debt |
|
|
13,931 |
|
|
|
(36 |
) |
|
|
12,765 |
|
|
|
(28 |
) |
|
|
26,696 |
|
|
|
(64 |
) |
Government securities |
|
|
39,762 |
|
|
|
(117 |
) |
|
|
4,519 |
|
|
|
(8 |
) |
|
|
44,281 |
|
|
|
(125 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
62,570 |
|
|
$ |
(168 |
) |
|
$ |
17,523 |
|
|
$ |
(37 |
) |
|
$ |
80,093 |
|
|
$ |
(205 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brighams other financial instruments include cash and cash equivalents, accounts receivable,
accounts payable and long-term debt. The carrying amount of cash and cash equivalents, accounts
receivable and accounts payable approximate fair value because of their immediate or short-term
maturities. The carrying value of Brighams senior credit facility approximates its fair market
value since it bears interest at floating market interest rates. The following are estimated fair
values and carrying values of our other financial instruments at each of these dates:
|
|
December 31, 2009 |
|
|
December 31, 2008 |
|
|
|
(in millions) |
|
|
(in millions) |
|
|
|
Carrying |
|
|
Fair |
|
|
Carrying |
|
|
Fair |
|
|
|
Amount |
|
|
Value |
|
|
Amount |
|
|
Value |
|
Senior Notes |
|
$ |
160,000 |
|
|
$ |
160,000 |
|
|
$ |
160,000 |
|
|
$ |
84,000 |
|
Series A Preferred Stock |
|
$ |
10,101 |
|
|
$ |
10,166 |
|
|
$ |
10,101 |
|
|
$ |
10,032 |
|
The fair value of Brighams Senior Notes is based upon current market quotes and is the estimated
amount required to purchase the Senior Notes on the open market.
F-24
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. Stock Based Compensation
Brigham applies Financial Accounting Standards Board Accounting Standards Codification Topic
718 Compensation Stock Compensation (FASB ASC 718) to account for stock based compensation.
The cost for all stock based awards is based on the grant date fair value estimated in accordance
with the provisions of FASB ASC 718 and is amortized on a straight-line basis over the requisite
service period including estimates of pre-vesting forfeiture rates. If actual forfeitures differ
from the estimates, additional adjustments to compensation expense may be required in future
periods. The maximum contractual life of stock based awards is ten years.
The estimated fair value of the options granted during the three years months ended December
31, 2009, 2008, and 2007 was calculated using a Black-Scholes-Merton option pricing model
(Black-Scholes). The following table summarizes the weighted average assumptions used in the
Black-Scholes model for each of the three years ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Risk-free interest rate |
|
|
2.64 |
% |
|
|
2.78 |
% |
|
|
3.88 |
% |
Expected life (in years) |
|
|
5.0 |
|
|
|
5.0 |
|
|
|
5.0 |
|
Expected volatility |
|
|
78 |
% |
|
|
56 |
% |
|
|
47 |
% |
Expected dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average fair value per share of stock compensation |
|
$ |
3.41 |
|
|
$ |
2.52 |
|
|
$ |
3.21 |
|
The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free
rate of interest for periods within the contractual life of the option is based on a zero-coupon
U.S. government instrument over the contractual term of the equity instrument. Expected volatility
is based on the historical volatility of Brighams stock for an equal period of the expected term.
Prior to the adoption of FASB ASC 718, Brigham presented all tax benefits of deductions
resulting from the exercise of stock options as operating cash flows in the Consolidated Statement
of Cash Flows. FASB ASC 718 requires the cash flow resulting from the tax deductions in excess of
the compensation cost recognized for those options (excess tax benefits) to be classified as
financing cash flows. Brigham did not record any excess tax benefits during the twelve months
ended December 31, 2009 and 2008.
The following table summarizes the components of stock based compensation included in general
and administrative expense (in thousands (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve Months Ended |
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Pre-tax stock based compensation expense |
|
$ |
4,282 |
|
|
$ |
2,926 |
|
|
$ |
3,443 |
|
Capitalized stock based compensation |
|
|
(2,003 |
) |
|
|
(1,334 |
) |
|
|
(1,538 |
) |
Tax benefit |
|
|
(798 |
) |
|
|
(557 |
) |
|
|
(667 |
) |
|
|
|
|
|
|
|
|
|
|
Stock based compensation expense, net |
|
$ |
1,481 |
|
|
$ |
1,035 |
|
|
$ |
1,238 |
|
|
|
|
|
|
|
|
|
|
|
Brigham provides an incentive plan for the issuance of stock options, stock appreciation
rights, stock, restricted stock, cash or any combination of the foregoing. The objective of this
plan is to provide incentive and reward key employees whose performance may have a significant
impact on the success of Brigham. It is Brighams policy to use unissued shares of stock when stock
options are exercised. The number of shares available under the plan is equal to the lesser of
9,966,003 or 12% of the total number of shares of common stock outstanding. At December 31, 2009,
approximately 2.8 million shares remain available for grant under the current incentive plan. The
Compensation Committee of the Board of Directors determines the type of awards made to each
participant and the terms, conditions and limitations applicable to each award. Except for one series of
stock option grants options granted subsequent to March 4,
1997 have an exercise price equal to the fair market value of Brighams common stock on the
date of grant, vest over five years and have a maximum contractual life of ten years.
F-25
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Brigham also maintains a director stock option plan under which stock options are awarded to
non-employee directors. Options granted under this plan have an exercise price equal to the fair
market value of Brigham common stock on the date of grant and vest over five years. Stockholders
have authorized the issuance of 1,000,000 shares to non-employee directors and approximately
566,800 remain available for grant under the director stock option plan.
The following table summarizes option activity under the incentive plans for each of the three
years ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Average |
|
|
|
|
|
|
|
Exercise |
|
|
|
|
|
|
Exercise |
|
|
|
|
|
|
Exercise |
|
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
Options outstanding at
beginning of year |
|
|
3,128,651 |
|
|
$ |
7.00 |
|
|
|
3,046,166 |
|
|
$ |
7.14 |
|
|
|
3,243,566 |
|
|
$ |
7.08 |
|
Granted |
|
|
2,846,975 |
|
|
$ |
4.80 |
|
|
|
534,000 |
|
|
$ |
5.08 |
|
|
|
105,000 |
|
|
$ |
7.06 |
|
Forfeited or cancelled |
|
|
(1,549,675 |
) |
|
$ |
8.30 |
|
|
|
(65,300 |
) |
|
$ |
7.79 |
|
|
|
(178,900 |
) |
|
$ |
8.19 |
|
Exercised |
|
|
(255,814 |
) |
|
$ |
4.89 |
|
|
|
(386,215 |
) |
|
$ |
5.35 |
|
|
|
(123,500 |
) |
|
$ |
3.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options outstanding at end of year |
|
|
4,170,137 |
|
|
$ |
5.14 |
|
|
|
3,128,651 |
|
|
$ |
7.00 |
|
|
|
3,046,166 |
|
|
$ |
7.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options exercisable at end of year |
|
|
691,962 |
|
|
$ |
6.17 |
|
|
|
1,954,851 |
|
|
$ |
7.17 |
|
|
|
1,869,066 |
|
|
$ |
6.62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant-date fair value of share options granted during the years ended
December 31, 2009, 2008, and 2007 was $3.41, $2.52, and $3.21, respectively. The total intrinsic
value of options exercised during the years ended December 31, 2009, 2008 and 2007 was $1.5 million,
$2.4 million, and $161,702, respectively.
The following table summarizes information about stock options outstanding at December 31,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
|
Options Exercisable |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Number |
|
|
Average |
|
|
Weighted- |
|
|
Number |
|
|
Average |
|
|
Weighted- |
|
|
|
Outstanding at |
|
|
Remaining |
|
|
Average |
|
|
Exercisable at |
|
|
Remaining |
|
|
Average |
|
|
|
December 31, |
|
|
Contractual |
|
|
Exercise |
|
|
December 31, |
|
|
Contractual |
|
|
Exercise |
|
Exercise Price |
|
2009 |
|
|
Life |
|
|
Price |
|
|
2009 |
|
|
Life |
|
|
Price |
|
$2.21 to $3.41 |
|
|
1,219,000 |
|
|
9.0 years |
|
$ |
2.26 |
|
|
|
29,000 |
|
|
2.5 years |
|
$ |
3.30 |
|
3.66 to 5.08 |
|
|
619,900 |
|
|
4.3 years |
|
$ |
4.86 |
|
|
|
251,900 |
|
|
2.1 years |
|
$ |
4.53 |
|
5.96 to 6.73 |
|
|
1,906,437 |
|
|
8.4 years |
|
$ |
6.01 |
|
|
|
224,262 |
|
|
3.1 years |
|
$ |
6.26 |
|
7.22 to 8.84 |
|
|
187,800 |
|
|
3.7 years |
|
$ |
7.71 |
|
|
|
112,800 |
|
|
2.9 years |
|
$ |
7.81 |
|
8.93 to 13.86 |
|
|
237,000 |
|
|
7.4 years |
|
$ |
11.66 |
|
|
|
74,000 |
|
|
2.4 years |
|
$ |
10.15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.21 to 13.86 |
|
|
4,170,137 |
|
|
7.7 years |
|
$ |
5.14 |
|
|
|
691,962 |
|
|
2.6 years |
|
$ |
6.17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value of options outstanding and exercisable at December 31, 2009 was
$35.1 million and $5.1 million, respectively. The aggregate intrinsic value represents the total
pre-tax value (the difference between Brighams closing stock price on the last trading day of 2009
and the exercise price, multiplied by the number of in-the-money options) that would have been
received by the option holders had all option holders exercised their options on December 31, 2009.
The amount of aggregate intrinsic value will change based on the fair market value of Brighams
stock.
Brigham commenced an exchange offer on July 13, 2009 pursuant to which eligible employees were offered the
opportunity to exchange outstanding stock options granted prior to April 21, 2009 for new stock options. On Monday,
August 10, 2009, pursuant to the exchange offer, eligible option holders tendered, and Brigham accepted for cancellation, 1,536,975 eligible stock options. After the cancellation of the options accepted by Brigham in the exchange offer, Brigham
granted new stock options with an exercise price of $5.955 per share, which was the mean of the high and low sales price per
share of Brigham shares as reported by The Nasdaq Global Select Market on August 10, 2009. The exchange of options
resulted in incremental compensation expense of $1.3 million that will be recognized over the five year vesting period of the new options.
As of December 31, 2009 there was approximately $7 million of total unrecognized compensation
expense related to unvested stock based compensation plans. This compensation expense is expected to be realized over the remaining vesting period of approximately 5 years.
F-26
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restricted Stock
During the year
ended December 31, 2009, Brigham issued 342,574, restricted shares of common stock as
compensation to officers and employees of
Brigham. Restrictions lapsed on 257,574 of these shares in 2009, resulting in recognition of approximately $1.4
million in compensation expense. Restrictions on 85,000 restricted shares lapse in 2014. As of December 31, 2009, there was approximately $2.1 million of total unrecognized
compensation expense related to unvested restricted stock. This compensation expense is expected to
be recognized, net of forfeitures, over the remaining vesting period of approximately 4 years.
Brigham has assumed a 6% weighted average forfeiture rate for restricted stock to be used in
calculating compensation expense. If actual forfeitures differ from the estimates, adjustments to
compensation expense may be required in future periods.
The following table reflects the outstanding restricted stock awards and activity related
thereto for the years ended December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended |
|
|
Year Ended |
|
|
|
December 31, 2009 |
|
|
December 31, 2008 |
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
Weighted- |
|
|
|
Number of |
|
|
Average |
|
|
Number of |
|
|
Average |
|
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
Restricted Stock Awards: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted shares outstanding at the beginning of the year |
|
|
593,260 |
|
|
$ |
7.58 |
|
|
|
653,623 |
|
|
$ |
7.16 |
|
Shares granted |
|
|
342,574 |
|
|
$ |
4.99 |
|
|
|
109,000 |
|
|
$ |
8.40 |
|
Lapse of restrictions |
|
|
(377,844 |
) |
|
$ |
6.02 |
|
|
|
(139,423 |
) |
|
$ |
6.46 |
|
Forfeitures |
|
|
(1,000 |
) |
|
$ |
9.49 |
|
|
|
(29,940 |
) |
|
$ |
6.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted shares outstanding at the end of the year |
|
|
556,990 |
|
|
$ |
7.04 |
|
|
|
593,260 |
|
|
$ |
7.58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14. Employee Benefit Plans
Brigham has adopted a defined contribution 401(k) plan for substantially all of its employees.
The plan provides for Brigham matching of employee contributions to the plan, at Brighams
discretion. During 2009, 2008, and 2007, Brigham provided a base match equal to 25% of eligible
employee contributions. Based on attainment of performance goals established at the beginning of
each fiscal year, there was no additional match for employee contributions made during 2009 and
2008. Brigham matched an additional 100% of eligible employee contributions made during 2007.
Brigham contributed approximately $143,000, $159,000, and $628,000 to the 401(k) plan for the years
ended December 31, 2009, 2008 and 2007, respectively, to match eligible contributions by employees.
15. Related Party Transactions
During the years ended December 31, 2009, 2008 and 2007, Brigham incurred costs of
approximately $2.3 million, $7.3 million, and $3.3 million, respectively, in fees for land
acquisition services performed by Brigham Land Management, owned by a brother of Brighams
Chairman, President and Chief Executive Officer and its Executive Vice President Land and
Administration. Other participants in Brighams 3-D seismic projects reimbursed Brigham for a
portion of these amounts. At December 31, 2009, 2008 and 2007, Brigham had a liability recorded in
accounts payable of approximately $30,000, $129,000, and $10,000, respectively, related to services
performed by this company.
Mr. Harold Carter, a director of Brigham, served as a consultant to Brigham on various aspects
of its business and strategic issues during 2008 and 2007. Fees paid for these services by Brigham
were approximately $30,000 for each the years ended December 31, 2008 and 2007. During each of the
years ended December 31, 2009, 2008 and 2007, additional payments of approximately $2,500, $12,000,
and $12,000, respectively, were made for the reimbursement of certain expenses. At December 31,
2009, 2008 and 2007, there were no payables related to these services recorded by Brigham.
F-27
BRIGHAM EXPLORATION COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Continued)
At December 31, 2009, 2008 and 2007, Brigham had short-term accounts receivable from Mr. Steve
Webster of
approximately zero, $2,900, and zero, respectively. These receivables represent the directors
share of costs related to his working interest ownership in the Staubach #1, Burkhart #1R and
Matthes-Huebner #1 wells that are operated by
Brigham. Mr. Webster obtained his interest in these wells through an exploration and
production company, Carrizo, that is not affiliated with Brigham. Mr. Webster was a co-founder of
Carrizo and is currently chairman of Carrizos board of directors. At December 31, 2009, 2008 and
2007, Carrizo owed Brigham $24,000, $119,000, and $35,000, respectively, for exploration and
production activities. Brigham owed Carrizo $6,000 at December 31, 2008. Brigham had no accounts
payable owed to Carrizo at December 31, 2009 and 2007. Mr. Webster is also chairman of the board
of directors for a well services company that Brigham made payments totaling approximately
$619,000, $470,000, and $1.3 million during 2009, 2008 and 2007, respectively. Brigham owed the
well services company approximately $27,000, $65,000, and $48,000 at December 31 2009, 2008 and
2007, respectively.
From time to time, in the normal course of business, Brigham has engaged a service company in
which Mr. Hobart Smith, one of Brighams current directors, owns stock and serves as a consultant.
Total payments to the service company during 2009, 2008 and 2007 were $420,000, $1.1 million, and
$1.2 million, respectively. At December 31, 2009, 2008 and 2007, Brigham owed the service company
approximately $102,000, $76,000, and $55,000, respectively.
16. Subsequent Events
Management evaluated and determined there were no subsequent events.
17. Supplemental Cash Flow Information
Supplemental cash flow information consists of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Cash paid for interest, net of capitalized amounts |
|
$ |
14,545 |
|
|
$ |
12,382 |
|
|
$ |
14,059 |
|
Noncash investing and financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized asset retirement obligations |
|
|
327 |
|
|
|
412 |
|
|
|
325 |
|
Accrued drilling costs |
|
|
(4,270 |
) |
|
|
4,927 |
|
|
|
(8,469 |
) |
Capitalized stock compensation |
|
|
2,003 |
|
|
|
1,334 |
|
|
|
1,538 |
|
18. Other Assets and Liabilities
Other current assets consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2009 |
|
|
2008 |
|
Prepayments |
|
$ |
767 |
|
|
$ |
1,897 |
|
Deferred taxes |
|
|
|
|
|
|
|
|
Other |
|
|
365 |
|
|
|
257 |
|
|
|
|
|
|
|
|
|
|
$ |
1,132 |
|
|
$ |
2,154 |
|
|
|
|
|
|
|
|
Other current liabilities consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
|
|
2009 |
|
|
2008 |
|
Accrued interest |
|
$ |
2,660 |
|
|
$ |
3,044 |
|
Derivative liabilities |
|
|
2,405 |
|
|
|
5 |
|
Other accrued liabilities |
|
|
2,641 |
|
|
|
2,016 |
|
|
|
|
|
|
|
|
|
|
$ |
7,706 |
|
|
$ |
5,065 |
|
|
|
|
|
|
|
|
F-28
BRIGHAM EXPORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Natural Gas Exploration and Production Activities
Oil and natural gas sales reflect the market prices of net production sold or transferred with
appropriate adjustments for royalties, net profits interest and other contractual provisions. Lease
operating expenses include lifting costs incurred to operate and maintain productive wells and
related equipment including such costs as operating labor, repairs and maintenance, materials,
supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of
oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration
and development activities. Results of operations do not include interest expense and general
corporate amounts.
Costs Incurred and Capitalized Costs
The costs incurred in oil and natural gas acquisition, exploration and development activities
follow (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Costs incurred for the year: |
|
|
|
|
|
|
|
|
|
|
|
|
Exploration (including geological and geophysical costs) |
|
$ |
10,566 |
|
|
$ |
43,229 |
|
|
$ |
37,324 |
|
Property acquisition |
|
|
15,416 |
|
|
|
35,299 |
|
|
|
18,554 |
|
Development |
|
|
54,641 |
|
|
|
110,155 |
|
|
|
69,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
80,243 |
|
|
$ |
188,683 |
|
|
$ |
125,729 |
|
|
|
|
|
|
|
|
|
|
|
Excluded costs for prospects are accumulated by year. Costs are reflected in the full cost
pool as the drilling program is executed or as costs are evaluated and deemed impaired. Brigham
anticipates these excluded costs will be included in the depletion computation over the next five
years. Brigham is unable to predict the future impact on depletion rates. The following is a
summary of capitalized costs (in thousands) excluded from depletion at December 31, 2009 by year
incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
Prior |
|
|
|
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
|
Years |
|
|
Total |
|
Property acquisition |
|
$ |
6,018 |
|
|
$ |
19,903 |
|
|
$ |
4,328 |
|
|
$ |
2,095 |
|
|
$ |
32,344 |
|
Exploration
(including
geological and
geophysical costs) |
|
|
(24 |
) |
|
|
4,877 |
|
|
|
1,932 |
|
|
|
19,675 |
|
|
|
26,460 |
|
Drilling |
|
|
8,333 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,333 |
|
Capitalized interest |
|
|
4,103 |
|
|
|
3,979 |
|
|
|
366 |
|
|
|
724 |
|
|
|
9,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
18,430 |
|
|
$ |
28,759 |
|
|
$ |
6,626 |
|
|
$ |
22,494 |
|
|
$ |
76,309 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Reserves and Related Financial Data
Information with respect to Brighams oil and natural gas producing activities is presented in
the following tables. Reserve quantities, as well as certain information regarding future
production and discounted cash flows, were determined by Brighams registered independent petroleum
consultants, Cawley, Gillespie and Associates, Inc.
F-29
BRIGHAM EXPORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
Oil and Natural Gas Reserve Data
The following
tables present Brighams independent petroleum consultants estimates of its
proved oil and natural gas reserves. Brigham emphasizes reserves are approximations and are
expected to change as additional information becomes available. Reservoir engineering is a
subjective process of estimating underground accumulations of oil and natural gas that cannot be
measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
Oil |
|
|
Gas |
|
|
|
(MBbls) |
|
|
(MMcf) |
|
Proved reserves at December 31, 2006 |
|
|
4,494 |
|
|
|
119,487 |
|
Revisions of previous estimates |
|
|
172 |
|
|
|
7,926 |
|
Extensions, discoveries and other additions |
|
|
1,546 |
|
|
|
14,349 |
|
Sales of mineral in place |
|
|
(227 |
) |
|
|
(22,493 |
) |
Production |
|
|
(392 |
) |
|
|
(12,626 |
) |
|
|
|
|
|
|
|
Proved reserves at December 31, 2007 |
|
|
5,593 |
|
|
|
106,643 |
|
|
|
|
|
|
|
|
Revisions of previous estimates |
|
|
413 |
|
|
|
(7,834 |
) |
Extensions, discoveries and other additions |
|
|
1,637 |
|
|
|
3,866 |
|
Production |
|
|
(578 |
) |
|
|
(7,996 |
) |
|
|
|
|
|
|
|
Proved reserves at December 31, 2008 |
|
|
7,065 |
|
|
|
94,679 |
|
|
|
|
|
|
|
|
Revisions of
previous estimates (a) |
|
|
2,055 |
|
|
|
(28,742 |
) |
Extensions,
discoveries and other additions (b) |
|
|
8,354 |
|
|
|
6,367 |
|
Sales of mineral in place |
|
|
(37 |
) |
|
|
(13 |
) |
Production |
|
|
(814 |
) |
|
|
(5,892 |
) |
|
|
|
|
|
|
|
Proved reserves at December 31, 2009 |
|
|
16,623 |
|
|
|
66,399 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves at December 31: |
|
|
|
|
|
|
|
|
2006 |
|
|
2,752 |
|
|
|
64,401 |
|
2007 |
|
|
3,321 |
|
|
|
49,367 |
|
2008 |
|
|
3,583 |
|
|
|
41,928 |
|
2009 |
|
|
5,342 |
|
|
|
29,178 |
|
(a) |
|
Revisions of previous estimates include performance and technical
revisions of 1,501 MBoe, economic revisions of (296) MBoe, acreage changes of (1,049) MBoe, and elimination of
PUD reserves that will not be developed within 5 years of (2,891) MBoe. |
(b) |
|
Extensions, discoveries and other additions include discoveries and associated PUDs
of 5,374 MBoe and additions resulting from the modernization of SEC reserve reporting rules of 4,041 MBoe. |
Proved reserves are estimated quantities of crude oil and natural gas, which geological and
engineering data indicate with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed reserves are proved
reserves that can be expected to be recovered through existing wells with existing equipment and
operating methods.
Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein
The following table presents a standardized measure of discounted future net cash inflows (in
thousands) relating to proved oil and natural gas reserves. For 2007 and 2008, future cash
flows
were computed by applying year-end prices of crude oil and natural gas relating to Brighams proved
reserves to the estimated year-end quantities of those reserves. Under new rules issued by the
Securities and Exchange Commission, the estimated future net cash flows at December 31, 2009
were determined using a 12-month average price. Future price changes were considered only to the
extent provided by contractual agreements in existence at year-end. Future production and
development costs were computed by estimating those expenditures expected to occur in developing
and producing the proved oil and natural gas reserves at the end of the year, based on year-end
costs. Actual future cash inflows may vary considerably, and the standardized measure does not
necessarily represent the fair value of Brighams oil and natural gas reserves.
F-30
BRIGHAM EXPORATION COMPANY
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Future cash inflows |
|
$ |
1,158,260 |
|
|
$ |
899,745 |
|
|
$ |
1,319,011 |
|
Future production costs |
|
|
(330,837 |
) |
|
|
(206,640 |
) |
|
|
(248,116 |
) |
Future development costs |
|
|
(266,733 |
) |
|
|
(160,304 |
) |
|
|
(160,506 |
) |
Future income tax expense |
|
|
(32,493 |
) |
|
|
(32,152 |
) |
|
|
(219,748 |
) |
|
|
|
|
|
|
|
|
|
|
Future net cash inflows |
|
|
528,197 |
|
|
|
500,649 |
|
|
|
690,641 |
|
10% annual discount for estimated timing of cash flows |
|
|
(281,721 |
) |
|
|
(221,353 |
) |
|
|
(296,127 |
) |
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash
flows |
|
$ |
246,476 |
|
|
$ |
279,296 |
|
|
$ |
394,514 |
|
|
|
|
|
|
|
|
|
|
|
Prices were adjusted to reflect applicable transportation and quality differentials on a
well-by-well basis to arrive at realized sales prices used to estimate Brighams reserves. The
prices used for Brighams reserve estimates were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural |
|
|
|
Oil |
|
|
Gas |
|
|
|
(Bbl) |
|
|
(MMbtu) |
|
December 31, 2009 |
|
$ |
61.18 |
|
|
$ |
3.87 |
|
December 31, 2008 |
|
|
44.60 |
|
|
$ |
5.71 |
|
December 31, 2007 |
|
|
96.01 |
|
|
$ |
7.10 |
|
Changes in the future net cash inflows discounted at 10% per annum follow (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2007 |
|
Beginning of period |
|
$ |
279,296 |
|
|
$ |
394,514 |
|
|
$ |
302,674 |
|
Sales of oil and natural gas produced,
net of production costs |
|
|
(48,439 |
) |
|
|
(107,144 |
) |
|
|
(107,221 |
) |
Previously estimated development costs
incurred during the period |
|
|
16,574 |
|
|
|
51,494 |
|
|
|
24,502 |
|
Extensions and discoveries |
|
|
75,803 |
|
|
|
30,175 |
|
|
|
66,342 |
|
Net change of prices and production costs |
|
|
(41,750 |
) |
|
|
(184,497 |
) |
|
|
164,728 |
|
Change in future development costs |
|
|
6,874 |
|
|
|
(28,901 |
) |
|
|
(31,586 |
) |
Changes in production rates (timing) |
|
|
(17,557 |
) |
|
|
(2,201 |
) |
|
|
(33,995 |
) |
Revisions of previous quantity estimates |
|
|
(41,726 |
) |
|
|
(16,436 |
) |
|
|
41,017 |
|
Accretion of discount |
|
|
28,722 |
|
|
|
49,130 |
|
|
|
33,730 |
|
Change in income taxes |
|
|
99 |
|
|
|
88,868 |
|
|
|
(62,161 |
) |
Sales of reserves in place |
|
|
(591 |
) |
|
|
|
|
|
|
(2,923 |
) |
Other |
|
|
(10,829 |
) |
|
|
4,294 |
|
|
|
(593 |
) |
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
246,476 |
|
|
$ |
279,296 |
|
|
$ |
394,514 |
|
|
|
|
|
|
|
|
|
|
|
F-31
Quarterly Financial Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
1 |
|
|
2 |
|
|
3 |
|
|
4 |
|
Revenue |
|
$ |
18,486 |
|
|
$ |
10,514 |
|
|
$ |
19,867 |
|
|
$ |
21,477 |
|
Operating income (loss)* |
|
|
(115,152 |
) |
|
|
(2,787 |
) |
|
|
4,750 |
|
|
|
4,273 |
|
Net income (loss)* |
|
|
(119,071 |
) |
|
|
(6,960 |
) |
|
|
491 |
|
|
|
2,548 |
|
Net income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
(2.60 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.01 |
|
|
$ |
0.03 |
|
Diluted |
|
$ |
(2.60 |
) |
|
$ |
(0.12 |
) |
|
$ |
0.01 |
|
|
$ |
0.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
Quarter |
|
|
|
1 |
|
|
2 |
|
|
3 |
|
|
4 |
|
Revenue |
|
$ |
25,071 |
|
|
$ |
25,026 |
|
|
$ |
47,191 |
|
|
$ |
30,500 |
|
Operating income (loss)* |
|
|
5,528 |
|
|
|
5,789 |
|
|
|
28,254 |
|
|
|
(230,745 |
) |
Net income (loss)* |
|
|
1,527 |
|
|
|
1,517 |
|
|
|
15,260 |
|
|
|
(180,551 |
) |
Net income (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.03 |
|
|
$ |
0.03 |
|
|
$ |
0.34 |
|
|
$ |
(3.95 |
) |
Diluted |
|
$ |
0.03 |
|
|
$ |
0.03 |
|
|
$ |
0.33 |
|
|
$ |
(3.93 |
) |
* |
|
Operating income (loss) and Net income (loss) include the impact from the writedown of the net
capitalized costs of Brighams oil and gas properties in the amounts of $114.8 million and
$237.2 million for the first quarter of 2009 and the fourth quarter 2008, respectively. |
F-32
INDEX TO EXHIBITS
|
|
|
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
|
3.1 |
|
|
|
|
Certificate of Incorporation (filed as Exhibit 3.1 to Brighams Registration Statement on Form
S-1 (Registration No. 333-22491), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
3.2 |
|
|
|
|
Certificates of Amendment to Certificate of Incorporation (filed as Exhibit 3.1.1 to Brighams
Registration Statement on Form S-3 (Registration No. 333-37558), and incorporated herein by
reference) |
|
|
|
|
|
|
|
|
3.3 |
|
|
|
|
Bylaws (filed as Exhibit 3.5 to Brighams Current Report on Form 8-K (dated May 28, 2009) and
incorporated herein by reference) |
|
|
|
|
|
|
|
|
3.4 |
|
|
|
|
Certificate of
Amendment to Certificate of Incorporation of Brigham Exploration Company dated
June 14, 2006, (filed as Exhibit 3.4 to Brighams
Annual Report on Form 10-K for the year ended December 31, 2008,
and incorporated herein by reference) |
|
|
|
|
|
|
|
|
3.5 |
|
|
|
|
Certificate of Amendment to Certificate of Incorporation of Brigham Exploration Company dated
October 7, 2009 (filed as Exhibit 3.5 to Brighams Current Report on Form 8-K (dated October
13, 2009) and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.1 |
|
|
|
|
Form of Common Stock Certificate (filed as Exhibit 4.1 to Brighams Registration Statement on
Form S-1 (Registration No. 333-22491), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.2 |
|
|
|
|
Certificate of Designations of Series A Preferred Stock (Par Value $.01 Per Share) of Brigham
Exploration Company filed October 31, 2000 (filed as Exhibit 4.1 to Brighams Current Report
on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.3 |
|
|
|
|
Certificate of Amendment of Certificate of Designations of Series A Preferred Stock (Par Value
$.01 Per Share) of Brigham Exploration Company, filed March 2, 2001 (filed as Exhibit 4.2.1 to
Brighams Annual Report on Form 10-K for the year ended December 31, 2000, and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
4.4 |
|
|
|
|
Certificate of Designations of Series B Preferred Stock (Par Value $.01 Per Share) of Brigham
Exploration Company filed December 20, 2002 (filed as Exhibit 4.4 to Brighams Annual Report
on Form 10-K for the year ended December 31, 2002, and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.5 |
|
|
|
|
Certificate of Elimination of Certificate of Designations of Series B Preferred Stock of
Brigham Exploration Company, dated June 4, 2004, (filed as Exhibit 99.2 to Brighams Current
Report on Form 8-K (filed July 20, 2004), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.6 |
|
|
|
|
Certificate of Designations of Series C Junior Preferred Stock of Brigham Exploration Company
effective as of December 10, 2008 (filed as Exhibit 3.1 to Brighams Current Report on Form
8-K (filed December 11, 2008), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.7 |
|
|
|
|
Indenture, dated April 20, 2006, among Brigham Exploration Company, the Guarantors named
therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.1 to Brighams Current
Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
4.8 |
|
|
|
|
Notations of Guarantees, dated April 20, 2006, among Brigham Exploration Company, the
Guarantors named therein and Wells Fargo Bank, N.A., as trustee, (filed as Exhibit 4.2 to
Brighams Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
4.9 |
|
|
|
|
Rule 144A 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.3 to
Brighams Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
4.10 |
|
|
|
|
Reg S 9 5/8% Senior Notes due 2014, dated April 20, 2006 (filed as Exhibit 4.4 to Brighams
Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by
reference) |
|
|
|
|
|
|
|
|
4.11 |
|
|
|
|
Notations of Guarantees dated as of April 9, 2007, among Brigham Exploration Company, the
Guarantors named therein and Wells Fargo Bank, N.A., as trustee (filed as Exhibit 4.2 to
Brighams Current Report on Form 8-K filed on April 13, 2007, and incorporated in by
reference) |
|
|
|
|
|
|
|
|
4.12 |
|
|
|
|
Rule 144A 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.3 to Brighams Current Report on
Form 8-K filed on April 13, 2007, and incorporated in by reference) |
|
|
|
|
|
|
|
|
4.13 |
|
|
|
|
Reg S 9 5/8% Senior Notes due 2014 (filed as Exhibit 4.4 on Form 8-K filed to Brighams
Current Report on April 13, 2007, and incorporated in by reference) |
|
|
|
|
|
|
|
|
4.14 |
|
|
|
|
Rights Agreement, dated as of December 10, 2008, between Brigham Exploration Company and
American Stock Transfer & Trust Company, LLC, as Rights Agent (filed as Exhibit 4.1 to
Brighams Current Report on Form 8-K (filed December 11, 2008), and incorporated herein by
reference) |
|
|
|
|
|
|
|
Number |
|
|
|
Description |
|
|
|
10.1 |
|
|
|
|
Amended and Restated Agreement of Limited Partnership of Brigham Oil & Gas, L.P., dated
December 30, 1997 by and among Brigham, Inc., Brigham Holdings I, L.L.C. and Brigham Holdings
II, L.L.C. (filed as Exhibit 10.1.4 to Brighams Annual Report on Form 10-K for the year ended
December 31, 1998, and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.2 |
|
|
|
|
Two Bridgepoint Lease Agreement dated September 30, 1996, by and between Investors Life
Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to
Brighams Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.3 |
|
|
|
|
First Amendment to Two Bridge Point Lease Agreement dated April 11, 1997 between Investors
Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.1
to Brighams Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.4 |
|
|
|
|
Second Amendment to Two Bridge Point Lease Agreement dated October 13, 1997 between Investors
Life Insurance Company of North America and Brigham Oil & Gas, L.P. (filed as Exhibit 10.9.2
to Brighams Registration Statement on Form S-1 (Registration No. 333-53873), and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.5 |
|
|
|
|
Letter dated April 17, 1998 exercising Right of First Refusal to Lease 3rd Option Space
(filed as Exhibit 10.9.3 to Brighams Registration Statement on Form S-1 (Registration No.
333-53873), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.6 |
|
|
|
|
Third Amendment to Two Bridge Point Lease Agreement dated November 1998 between Hub Properties
Trust and Brigham Oil & Gas, L.P. (filed as Exhibit 10.13 to Brighams Annual Report on Form
10-K for the year ended December 31, 2004 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.7 |
|
|
|
|
Fourth Amendment to Two Bridge Point Lease Agreement dated February 7, 2002 between Hub
Properties Trust and Brigham Oil & Gas, L.P. (filed as Exhibit 10.14 to Brighams Annual
Report on Form 10-K for the year ended December 31, 2004 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.8 |
|
|
|
|
Fifth Amendment to Two Bridge Point Lease Agreement dated December 20, 2004 between Hub
Properties Trust, a Maryland real estate investment trust, and Brigham Oil & Gas, L.P. (filed
as Exhibit 10.15 to Brighams Annual Report on Form 10-K for the year ended December 31, 2004
and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.9 |
|
|
|
|
Registration Rights Agreement dated February 26, 1997 by and among Brigham Exploration
Company, General Atlantic Partners III L.P., GAP-Brigham Partners, L.P., RIMCO Partners, L.P.
II, RIMCO Partners L.P. III, and RIMCO Partners, L.P. IV, Ben M. Brigham, Anne L. Brigham,
Harold D. Carter, Craig M. Fleming, David T. Brigham and Jon L. Glass (filed as Exhibit 10.29
to Brighams Registration Statement on Form S-1 (Registration No. 333-22491), and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.10 |
|
|
|
|
Form of Employee Stock Ownership Agreement (filed as Exhibit 10.31 to Brighams Registration
Statement on Form S-1 (Registration No. 333-22491), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.11 |
* |
|
|
|
Form Change of Control Agreement dated as of September 20, 1999 between Brigham Exploration
Company and certain Officers (filed as Exhibit 10.3 to Brighams Quarterly Report on Form 10-Q
for the fiscal quarter ended September 30, 1999 and incorporated by reference herein) |
|
|
|
|
|
|
|
|
10.12 |
|
|
|
|
Registration Rights Agreement dated November 1, 2000 by and between Brigham Exploration
Company, DLJ MB Funding III, Inc., and DLJ ESC II, LP. (filed as Exhibit 10.10 to Brighams
Current Report on Form 8-K, as amended (filed November 8, 2000), and incorporated herein by
reference) |
|
|
|
|
|
|
|
|
10.13 |
|
|
|
|
First Amendment to Registration Rights Agreement, dated February 20, 2001, by and among
Brigham Exploration Company, DLJMB Funding III, Inc., DLJ Merchant Banking Partners III, LP,
DLJ ESC II, LP and DLJ Offshore Partners III, CV (filed as Exhibit 10.71 to Brighams Annual
Report on Form 10-K for the year ended December 31, 2000, and incorporated herein by
reference) |
|
|
|
|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
|
10.14 |
|
|
|
|
Registration Rights Agreement dated December 20, 2002 between Brigham Exploration Company and
Shell Capital Inc. (filed as Exhibit 10.50 to Brighams Annual Report on Form 10-K for the
year ended December 31, 2002 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.15 |
|
|
|
|
Second Amendment to Registration Rights Agreement dated December 21, 2002 between Brigham
Exploration Company and Credit Suisse First Boston Entities (filed as Exhibit 10.51 to
Brighams Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.16 |
|
|
|
|
Third Amendment to Registration Rights Agreement May 24, 2004 between Brigham Exploration
Company and Credit Suisse First Boston Entities (filed as Exhibit 99.1 to Brighams Current
Report on Form 8-K (filed July 20, 2004), and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.17 |
|
|
|
|
Fourth Amended and Restated Credit Agreement, dated June 29, 2005 between Brigham Oil & Gas,
L.P., Bank of America, N.A., The Royal Bank of Scotland plc, BNP Paribas and Banc of America
Securities LLC. (filed as Exhibit 10.1 to Brighams Quarterly Report on Form 10-Q for the
fiscal quarter ended June 30, 2005 and incorporated herein by reference) |
|
|
|
|
|
|
|
|
10.18 |
|
|
|
|
The Resignation of Agent, Appointment of Successor Agent and Assignment of Security
Instruments dated June 29, 2005 by and among Brigham Oil & Gas, L.P., Société Generale and
Bank of America, N.A. (filed as Exhibit 10.2 to Brighams Quarterly Report on Form 10-Q for
the fiscal quarter ended June 30, 2005 and incorporated herein by reference) |
|
|
|
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10.19 |
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|
Purchase Agreement dated April 12, 2006, among Brigham Exploration Company, the Guarantors
named therein (filed as Exhibit 10.1 to Brighams Current Report on Form 8-K, as amended
(filed April 24, 2006), and incorporated herein by reference) |
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10.20 |
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|
Registration Rights Agreement, dated April 20, 2006, among Brigham Exploration Company, the
Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 10.2 to
Brighams Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated
herein by reference) |
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10.21 |
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|
First Amendment to Fourth Amended and Restated Credit Agreement, between Brigham Exploration
Company and the banks named therein, dated April 10, 2006 (filed as Exhibit 10.3 to Brighams
Current Report on Form 8-K, as amended (filed April 24, 2006), and incorporated herein by
reference) |
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10.22 |
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|
Second Amendment to Fourth Amended and Restated Credit Agreement, between Brigham Exploration
Company and the banks named therein, dated March 27, 2007 (filed as Exhibit 10.3 to Brighams
Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference) |
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10.23 |
* |
|
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|
Form of the Amended and Restated Indemnity Agreement, dated November 9, 2006 (filed as Exhibit
99.1 to Brighams Current Report on Form 8-K, as amended (filed December 5, 2006), and
incorporated herein by reference) |
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10.24 |
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|
Purchase Agreement dated March 30, 2007, among Brigham Exploration Company, the Guarantors
named therein and the Initial Purchasers named therein (filed as Exhibit 10.1 to Brighams
Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference) |
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10.25 |
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|
Registration Rights Agreement dated April 9, 2007, among Brigham Exploration Company, the
Guarantors named therein and the Initial Purchasers named therein (filed as Exhibit 10.2 to
Brighams Current Report on Form 8-K filed on April 13, 2007 and incorporated in by reference) |
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10.26 |
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|
Amendment to Securities Purchase Agreement dated July 31, 2008, between Brigham Exploration
Company and DLJMB Funding III, Inc., DLJ ESC II, LP, DLJ Merchant Banking Partners III, L.P.,
and other parties (filed as Exhibit 10.41 to Brighams Current Report on Form 8-K (filed
August 5, 2008) and incorporated herein by reference) |
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Number |
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|
Description |
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10.27 |
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Agreement Relating to Voting of Shares dated July 31, 2008, between Brigham Exploration
Company and DLJ Merchant Banking Partners III, L.P., DLJ Offshore Partners III, C.V., DLJ
Offshore Partners III-1, C.V., DLJ Offshore Partners III-2, C.V., DLJ MB Partners III GmbH &
Co. KG, Millennium Partners II, L.P., MBP III Plan Investors, L.P., DLJ ESC II, L.P. and DLJMB
Funding III, Inc. (filed as Exhibit 10.42 to Brighams Current Report on Form 8-K (filed
August 5, 2008) and incorporated herein by reference) |
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10.28 |
|
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|
Third Amendment to the Fourth Amended and Restated Credit Agreement dated as of June 29, 2005
(filed as Exhibit 10.43 to Brighams Current Report on Form 8-K (filed November 12, 2008) and
incorporated herein by reference) |
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10.29 |
* |
|
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|
1997 Incentive Plan of Brigham Exploration Company (as amended effective August 19, 2009)
(filed as Exhibit 10.50 to Brighams Current Report on Form 8-K (filed October 13, 2009) and
incorporated herein by reference) |
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10.30 |
* |
|
|
|
Form of Restricted Stock Agreement under the 1997 Incentive Plan of Brigham Exploration
Company (filed as Exhibit 10.45 to Brighams Current Report on Form 8-K (filed December 29,
2008) and incorporated herein by reference) |
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10.31 |
* |
|
|
|
Form of Option Agreement (Non-Qualified Stock Option) under the 1997 Incentive Plan of Brigham
Exploration Company (filed as Exhibit 10.46 to Brighams Current Report on Form 8-K (filed
December 29, 2008) and incorporated herein by reference) |
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10.32 |
* |
|
|
|
Form of Option Agreement (Incentive Option) under the 1997 Incentive Plan of Brigham
Exploration Company (filed as Exhibit 10.47 to Brighams Current Report on Form 8-K (filed
December 29, 2008) and incorporated herein by reference) |
|
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10.33 |
* |
|
|
|
Brigham Exploration Company 1997 Director Stock Option Plan (as amended effective January 1,
2009) (filed as Exhibit 10.48 to Brighams Current Report on Form 8-K (filed December 29,
2008) and incorporated herein by reference) |
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10.34 |
* |
|
|
|
Form of Non-Qualified Stock Option Agreement under the 1997 Director Stock Option Plan (filed
as Exhibit 10.49 to Brighams Current Report on Form 8-K (filed December 29, 2008) and
incorporated herein by reference) |
|
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|
|
|
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10.35 |
* |
|
|
|
Form of Amendment to the Change of Control Agreement (filed as Exhibit 10.50 to Brighams
Current Report on Form 8-K (filed December 29, 2008) and incorporated herein by reference) |
|
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|
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10.36 |
* |
|
|
|
Amendment to the Employment Agreement between the Company and Ben M. Brigham dated as of
December 23, 2008 (filed as Exhibit 10.51 to Brighams Current Report on Form 8-K (filed
December 29, 2008) and incorporated herein by reference) |
|
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10.37 |
|
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|
|
Confirmation of Notice of Termination of Consulting Agreement with Harold D. Carter, between
Brigham Oil & Gas, L.P. and Harold D. Carter, effective as of January 1, 2009 (filed as
Exhibit 10.41 to Brighams Quarterly Report on Form 10-Q for the fiscal quarter ended March
31, 2009 and incorporated herein by reference) |
|
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10.38 |
|
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|
|
1997 Incentive Plan Amendment to Option Agreements, effective as of April 22, 2009 (filed as
Exhibit 10.42 to Brighams Quarterly Report on Form 10-Q for the fiscal quarter ended March
31, 2009 and incorporated herein by reference) |
|
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10.39 |
|
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|
|
Fourth Amendment to the Fourth Amended and Restated Credit Agreement dated as of June 28, 2005
(filed as Exhibit 10.43 to Brighams Current Report on Form 8-K (filed May 28, 2009) and
incorporated herein by reference) |
|
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|
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|
10.40 |
|
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|
|
Fifth Amendment to the Fourth Amended and Restated Credit Agreement dated as of June 28, 2005
(filed as Exhibit 10.45 to Brighams Current Report on Form 8-K (filed July 28, 2009) and
incorporated herein by reference) |
|
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|
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|
10.41 |
|
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|
|
Form of Non-Qualified Stock Option Agreement (filed as Exhibit 10.49 to Brighams Quarterly
Report on Form 10-Q for the fiscal quarter ended June 30, 2009) and incorporated herein by
reference) |
|
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|
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|
10.42 |
|
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|
|
Form of Non-Qualified Stock Option Agreement under the 1997 Director Stock Option Plan (filed
as Exhibit 10.3 to Brighams Quarterly Report on Form 10-Q for the fiscal quarter ended
September 30, 2009 and incorporated herein by reference) |
|
|
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|
|
|
|
Number |
|
|
|
Description |
|
|
|
|
|
|
|
|
10.43 |
|
|
|
|
Form of Amendment to Non-Qualified Stock Option Agreements (filed as Exhibit 10.4 to Brighams
Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2009 and incorporated
herein by reference) |
|
|
|
|
|
|
|
|
10.44 |
|
|
|
|
Amendment to Brigham Exploration Company 1997 Director Stock Option Plan, effective as of
September 23, 2009 (filed as Exhibit 10.6 to Brighams Quarterly Report on Form 10-Q for the
fiscal quarter ended September 30, 2009 and incorporated herein by reference) |
|
|
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|
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|
10.45 |
|
|
|
|
Amendment to Non-Qualified Stock Option Agreements under the 1997 Director Stock Option Plan,
effective as of September 23, 2009 (filed as Exhibit 10.7 to Brighams Quarterly Report on
Form 10-Q for the fiscal quarter ended September 30, 2009 and incorporated herein by
reference) |
|
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21 |
|
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|
Subsidiaries of the Registrant |
|
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23.1 |
|
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|
|
Consent of KPMG LLP, Independent Registered Public Accounting Firm |
|
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23.2 |
|
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|
Consent
of Cawley, Gillespie & Associates, Inc. |
|
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|
31.1 |
|
|
|
|
Certification of Chief Executive Officer pursuant to Sec. 302 of the Sarbanes-Oxley Act of 2002 |
|
|
|
|
|
|
|
|
31.2 |
|
|
|
|
Certification of Chief Financial Officer pursuant to Sec. 302 of the Sarbanes-Oxley Act of 2002 |
|
|
|
|
|
|
|
|
32.1 |
|
|
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. SECTION 1350 |
|
|
|
|
|
|
|
|
32.2 |
|
|
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. SECTION 1350 |
|
|
|
|
|
|
|
|
99.1 |
|
|
|
|
Report of Cawley, Gillespie & Associates, Inc. |
|
|
|
* |
|
Management contract or compensatory plan. |