Attached files
file | filename |
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EX-31.2 - EXHIBIT 31.2 - Atlas Resources Public #17-2008 (B) L.P. | c98379exv31w2.htm |
EX-31.1 - EXHIBIT 31.1 - Atlas Resources Public #17-2008 (B) L.P. | c98379exv31w1.htm |
EX-99.1 - EXHIBIT 99.1 - Atlas Resources Public #17-2008 (B) L.P. | c98379exv99w1.htm |
EX-23.1 - EXHIBIT 23.1 - Atlas Resources Public #17-2008 (B) L.P. | c98379exv23w1.htm |
EX-32.2 - EXHIBIT 32.2 - Atlas Resources Public #17-2008 (B) L.P. | c98379exv32w2.htm |
EX-32.1 - EXHIBIT 32.1 - Atlas Resources Public #17-2008 (B) L.P. | c98379exv32w1.htm |
United States
Securities and Exchange Commission
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-K
(Mark One)
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2009
o | 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 333-144070-02
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
(Exact name of registrant as specified in its charter)
Delaware | 26-1466056 | |
(State or other jurisdiction of | (I.R.S. Employer | |
Incorporation or organization) | Identification No.) | |
Westpointe Corporate Center One | ||
1550 Coraopolis Heights Road, 2nd Floor | ||
Moon Township, PA | 15108 | |
(Address of principal executive offices) | (Zip Code) |
Registrants telephone number (412) 262-2830
Securities registered under Section 12(b) of the Exchange Act.
Title of each class | Name of each exchange on which registered | |
None | None |
Securities registered under Section 12 (g) of the Exchange Act: Investor General Partner Units and Limited Partner Units
(Title of Class)
(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 o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15 (d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days, Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this form 10-K þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer, non-accelerating filer and smaller reporting company in Rule 12b-2
of the Exchange Act (Check one):
Large accelerated filer o | Accelerated filer o | Non-accelerated filer o | Smaller reporting company þ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o No þ
DOCUMENTS INCORPORATED BY REFERENCE: None
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO ANNUAL REPORT
ON FORM 10-K
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO ANNUAL REPORT
ON FORM 10-K
PAGE | ||||
3-5 | ||||
6-10 | ||||
11 | ||||
11 | ||||
11 | ||||
12-15 | ||||
16-36 | ||||
36 | ||||
36-37 | ||||
37 | ||||
37-39 | ||||
39 | ||||
40 | ||||
40 | ||||
41 | ||||
41 | ||||
42 | ||||
2
The matters discussed within this report include forward-looking statements. These
statements may be identified by the use of forward-looking terminology such as anticipate,
believe, continue, could, estimate, expect, intend, may, might, plan,
potential, predict, should, or will, or the negative thereof or other variations thereon or
comparable terminology. In particular, statements about our expectations, beliefs, plans,
objectives, assumptions or future events or performance contained in this report are
forward-looking statements. We have based these forward-looking statements on our current
expectations, assumptions, estimates, and projections. While we believe these expectations,
assumptions, estimates, and projections are reasonable, such forward-looking statements are only
predictions and involve known and unknown risks and uncertainties, many of which are beyond our
control. These and other important factors may cause our actual results, performance or
achievements to differ materially from any future results, performance or achievements expressed or
implied by these forward-looking statements.
PART I
ITEM 1. | DESCRIPTION OF BUSINESS |
General. We were formed as a Delaware limited partnership on May 7, 2007 with Atlas Resources,
LLC as our Managing General Partner or MGP. Atlas Resources, LLC is an indirect subsidiary of Atlas
Energy, Inc. (NASDAQ: ATLS) or Atlas Energy.
Atlas Energys focus is on the development and production of natural gas and oil in the
Appalachian Basin, Michigan Basin and the Illinois Basin, regions of the United States of America.
Atlas Energy is also leading sponsor of and manages tax-advantaged direct investment partnerships,
in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy
Resources, LLC is managed by Atlas Energy Management, Inc., through which Atlas Energy, Inc.
provides Atlas Energy Resources, LLC with the personnel necessary to manage its assets and raise
capital.
We drilled and currently operate wells located in Pennsylvania, Tennessee and Ohio. We have no
employees and rely on our MGP for management, which, in turn, relies on its parent company, Atlas
Energy, Inc. for administrative services. See Item 11 Executive Compensation.
We received total cash subscriptions from investors of $236,027,000, which were paid to our
MGP acting as operator and general drilling contractor under our drilling and operating agreements.
Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a
total capital contribution of $91,524,500. We have drilled 506 developmental wells to the
Clinton/Medina, Upper Devonian Sandstones, Southern Appalachia Shale and Marcellus geological
formations in Pennsylvania, Tennessee and Ohio.
Our wells are currently producing natural gas and oil which are our only products. Most of our
gas is gathered and delivered to market through Laurel Mountain Midstream, LLCs gas gathering
system, a newly formed joint-venture between Atlas Energy, Inc.s affiliate Atlas Pipeline Partners
L.P. (NYSE: APL) and The Williams Companies Inc. (NYSE: WMB).
We do not plan to sell any of our wells and will continue to produce them until they are
depleted or become uneconomical to produce, at which time they will be plugged and abandoned or
sold. No other wells will be drilled and no additional funds will be required for drilling. See
Item 2 Properties for information concerning our wells.
3
Our ongoing operating and maintenance costs have been and are expected to be fulfilled through
revenues from the sale of our natural gas and oil production. We pay our MGP a monthly well
supervision fee of $377 per well, as outlined in our drilling and operating agreement. This well
supervision fee covers all normal and regularly recurring operating expenses for the production and
sale of natural gas and oil, such as:
| well tending, routine maintenance and adjustment; |
||
| reading meters, recording production, pumping, maintaining appropriate books and
records; and |
||
| preparation of reports for us and government agencies. |
The well supervision fees, however, do not include costs and expenses related to the purchase
of certain equipment, materials and brine disposal. If these expenses are incurred, we pay cost for
third-party services, materials, and a reasonable charge for services performed directly by our MGP
or its affiliates. Also, beginning one year after each of our wells has been placed into production
our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and
abandonment costs of the well.
Markets and Competition. The availability of a ready market for natural gas and oil produced
by us, and the price obtained, depends on numerous factors beyond our control, including the extent
of domestic production, imports of foreign natural gas and oil, political instability or terrorist
acts in oil and gas producing countries and regions, market demand, competition from other energy
sources, the effect of federal regulation on the sale of natural gas and oil in interstate
commerce, other governmental regulation of the production and transportation of natural gas and oil
and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is
responsible for selling our natural gas production. Our natural gas is sold as discussed in Item 2
Properties. During 2009 and 2008, we experienced no problems in selling our natural gas and oil.
Product availability and price are the principal means of competition in selling natural gas and
oil production.
While it is impossible to accurately determine our comparative position in the industry, we do
not consider our operations to be a significant factor in the industry. See Item 2 Properties
regarding the marketing of our natural gas and oil.
Governmental Regulation. The energy industry in general is heavily regulated by federal and
state authorities, including regulation of production, environmental quality and pollution control.
The intent of federal and state regulations generally is to prevent waste, protect rights to
produce natural gas and oil between owners in a common reservoir and control contamination of the
environment. Failure to comply with regulatory requirements can result in substantial fines and
other penalties. The following discussion of the regulation of the United States of America energy
industry is not intended to constitute a complete discussion of the various statutes, rules,
regulations and environmental orders to which our operations may be subject.
Regulation of oil and gas producing activities. State regulatory agencies where a producing
natural gas well is located provide a comprehensive statutory and regulatory scheme for oil and gas
operations such as ours including supervising the production activities and the transportation of
natural gas sold in intrastate markets. Our oil and gas operations in Pennsylvania are regulated by
the Department of Environmental Resources, Division of Oil and Gas, our oil and gas operations in
Tennessee are regulated by the Tennessee Department of Environment and Conservation and the
Division of Geology and our oil and gas operations in Ohio are regulated by the Ohio Department of
Natural Resources, Division of Oil and Gas.
4
Among other things, these regulations involve:
| new well permit and well registration requirements, procedures and fees; |
| minimum well spacing requirements; |
| restriction on well locations and underground gas storage; |
| certain well site restoration, groundwater protection and safety measures; |
| landowner notification requirements; |
| certain bonding or other security measures; |
| various reporting requirements; |
| well plugging standards and procedures; and |
| broad enforcement powers. |
Environmental and Safety Regulation. Under the Comprehensive Environmental Response,
Compensation and Liability Act, the Toxic Substances Control Act, the Resource Conservation and
Recovery Act, the Oil Pollution Act of 1990, the Clean Air Act, and other federal and state laws
relating to the environment, owners and operators of wells producing natural gas or oil can be
liable for fines, penalties and clean-up costs for pollution caused by the wells. Moreover, the
owners or operators liability can extend to pollution costs from situations that occurred prior to
their acquisition of the assets. State public utility regulators have either adopted federal
standards or promulgated their own safety requirements consistent with the federal regulations.
We believe we have complied in all material respects with applicable federal and state
regulations and do not expect that these regulations will have a material adverse impact on our
operations. Our producing activities also must comply with various federal, state, and local laws
not mentioned, including those covering the discharge of materials into the environment, or
otherwise relating to the protection of the environment.
Where can you find more information. We file a Form 10-K Annual Report and Form 10-Q Quarterly
Reports as well as other non-recurring special purpose reports with the Securities and Exchange
Commission. A complete list of our filings is available on the Securities and Exchange Commissions
website at www.sec.gov. Any of our filings are also available at the SECs Public Reference Room at
100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at 1-800-
SEC-0330 for further information.
Additionally, our MGP will provide copies of any of these reports to you without charge. Such
requests should be made to:
Atlas Resources Public 17-2008 (B) L.P.
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA 15108
Westpointe Corporate Center One
1550 Coraopolis Heights Road, 2nd Floor
Moon Township, PA 15108
5
ITEM 2. | DESCRIPTION OF PROPERTIES |
Drilling Activity. As of December 31, 2009, we have drilled 506 gross wells. All of our wells
drilled were development wells, which represents a well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive. Also, see Item 7
Managements Discussion and Analysis of Financial Condition or Plan of Operations regarding our
revenues recognized, costs and expenses we incurred, and our daily production volumes, average
sales prices and production cost per equivalent unit during the period indicated.
Development Wells | ||||||||||||||||
Productive(1) | Dry(2) | |||||||||||||||
Year Ended December 31, | Gross(3) | Net(4) | Gross(3) | Net(4) | ||||||||||||
2008 |
506.00 | 474.51 | | |
(1) | A productive well generally refers to a well that is not a dry hole. |
|
(2) | A dry hole generally refers to a well found to be incapable of producing either
oil or gas in sufficient quantities to justify completion as an oil or gas well. The
term completion refers either to the installation of permanent equipment for the
production of oil or gas or, in the case of a dry hole, to the reporting of the
abandonment of the well to the appropriate regulatory agency. |
|
(3) | A gross well is a well in which we have a working interest. |
|
(4) | A net well equals the actual working interest we own in one gross well divided
by one hundred. For example, a 50% working interest in a well is one gross well, but a
0.5 net well. |
Summary of Producing Wells. The table below presents the number of producing gross and
net wells at December 31, 2009, in which we have a working interest. All wells are located in the
Appalachian Basin.
Number of Producing Wells | ||||||||
Gross | Net | |||||||
Gas |
506.00 | 474.51 |
Production. The following table presents the quantities of natural gas, oil and liquids we
produced (net to our interest), our average sales price, and our average production (lifting) cost
per equivalent unit of production for the periods indicated.
Average | ||||||||||||||||||||||||||||
Year | Production Cost | |||||||||||||||||||||||||||
Ended | Production | Average Sales Price | (Lifting Cost) | |||||||||||||||||||||||||
December 31, | Oil (bbls)(1) | Gas (mcf)(1) | Liquids (Mcf)(1) | per bbl(1) (3) (5) | per mcf(1)(3) (4) | Liquids (Mcf)(1) | per mcfe(1) (2) | |||||||||||||||||||||
2009 |
26,000 | 4,866,200 | 1,100 | $ | 58.89 | $ | 7.71 | $ | 4.21 | $ | 2.34 | |||||||||||||||||
2008 |
9,100 | 2,470,600 | | $ | 91.41 | $ | 9.19 | $ | | $ | 1.81 |
(1) | Mcf represents one thousand cubic feet of natural gas. Mcfe represent a thousand
cubic feet equivalent. Oil production is converted to mcfe at the rate of six mcf per
barrel (bbl). |
|
(2) | Lifting costs include labor to operate the wells and related equipment, repairs
and maintenance, materials and supplies, property taxes, insurance and gathering
charges. |
|
(3) | Average sales prices represent accrual basis pricing after reversing the effect
of previously recognized gains resulting from prior period impairment charges. |
|
(4) | Average gas prices are calculated by including in total revenue derivative gains
previously recognized into income and dividing by the total volume for the period.
Previously recognized derivative gains were $4,522,100 for the year ended December 31,
2009. The derivative gains are included in other comprehensive income and resulted from
prior period impairment charges. |
|
(5) | Average oil prices are calculated by including in total revenue derivative gains
previously recognized into income and dividing by the total volume for the period.
Previously recognized derivative gains were $168,100 for the year ended December 31,
2009. The derivative gains are included in other comprehensive income and resulted from
prior period impairment charges. |
6
Natural Gas and Oil Reserve Information. In December 2008, the Securities and Exchange
Commission (SEC) approved revisions to its oil and gas reporting disclosures by adopting
amendments to Rule 4-10 of Regulation S-X and Items 201, 801, and 802 of Regulation S-K effective
for fiscal years ending on or after December 31, 2009. These new disclosure requirements are
referred to as Modernization of Oil and Gas Reporting and include provisions that:
| Introduce a new definition of oil and gas producing activities. This new definition
allows companies to include in their reserve base volumes from unconventional resources.
Such unconventional resources include bitumen extracted from oil sands and oil and gas
extracted from coal beds and shale formations. |
| Report oil and gas reserves using an unweighted average price using the prior 12-month
period, based on the closing prices on the first day of each month, rather than year-end
pricing. This should maximize the comparability of reserve estimates among companies and
mitigate the distortion of the estimates that arises when using a single pricing date. |
| Permit companies to disclose their probable and possible reserves on a voluntary basis.
Current rules limit disclosure to only proved reserves. |
| Update and revise reserve definitions to reflect changes in the oil and gas industry and
new technologies. New updated definitions include by geographic area and reasonable
certainty. |
| Permit the use of new technologies to determine proved reserves if those technologies
have been demonstrated empirically to lead to reliable conclusions about reserves volumes. |
| Require additional disclosures regarding the qualifications of the chief technical
person who oversees the companys overall reserve estimation process. Additionally,
disclosures are required related to internal controls over reserve estimation, as well as a
report addressing the independence and qualifications of a companys reserves preparer or
auditor based on Society of Petroleum Engineers criteria. |
We have complied with these disclosure requirements for the year ended December 31, 2009.
The following tables summarize information regarding our estimated proved natural gas and oil
reserves as of the dates indicated. Proved reserves are the estimated quantities of crude oil and
natural gas, which, by an analysis of geological and engineering data, can be estimated with
reasonable certainty to be recoverable in future years from known reservoirs under existing
economic conditions, operating methods and government regulations (i.e., prices and costs as of the
date the estimate is made). Prices include consideration of changes in existing prices provided
only by contractual arrangements, but not on escalations based upon future conditions. The
estimated reserves include reserves attributable to our direct ownership interests in oil and gas
properties. For the year ended December 31, 2009, we based our estimates of proved reserves on the
12-month unweighted average price of the first-day-of-the-month price for each calendar month 2009
and then applied any basis and British Thermal Units (btu) differentials specifically applicable
to each oil and gas property based on location and pricing details. For the year ended December 31,
2008, we based our estimates of proved reserves using the natural gas and oil prices as of December
31, 2008 of the respective year. The following table summarizes the natural gas and oil prices used
in the estimation of proved reserves:
December 31, | ||||||||
2009 | 2008 | |||||||
Natural gas (per mcf) |
$ | 3.87 | $ | 5.71 | ||||
Oil (per bbl) |
61.18 | 44.80 |
7
Reserve estimates are imprecise and may change as additional information becomes available.
Furthermore, estimates of natural gas and oil reserves are projections based on engineering data.
There are uncertainties inherent in the interpretation of this data as well as the projection of
future rates of production. Reservoir engineering is a subjective process of estimating underground
accumulations of natural gas and oil 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. The preparation of our natural gas and oil reserve
estimates were completed in accordance with our prescribed internal control procedures, which
include verification of input data delivered to our third-party reserve specialist, as well as a
multi-functional management review. For the year ended December 31, 2009, we retained Wright &
Company, a third-party, independent petroleum engineering firm, to prepare a report of proved
reserves. The reserves report included a detailed review of our properties. Wright & Companys
evaluation was based on more than 35 years of experience in the estimation of and evaluation of
petroleum reserves, specified economic parameters, operating conditions, and government regulations
applicable as of December 31, 2009. The Wright & Company report, including the qualifications of
the chief technical person responsible for the report, was prepared in accordance with generally
accepted petroleum engineering and evaluation principles and is attached as Exhibit 99.1 to this
Annual Report on Form 10-K. Results of production subsequent to the date of the estimate may
justify revision of this estimate. Future prices received from the sale of natural gas and oil may
be different from those estimated by our independent petroleum engineering firm in preparing their
reports. The amounts and timing of future operating costs may also differ from those used.
Accordingly, the reserves set forth in the following tables ultimately may not be produced and the
proved undeveloped reserves may not be developed within the periods anticipated. You should not
construe the estimated PV-10 and standardized measure values as representative of the current or
future fair market value of our proved natural gas and oil properties. PV-10 and standardized
measure values are based upon projected cash inflows, which do not provide for changes in natural
gas and oil prices or for the escalation of expenses. The meaningfulness of these estimates depends
upon the accuracy of the assumptions upon which they were based.
8
We evaluate natural gas reserves at constant temperature and pressure. A change in either of
these factors can affect the measurement of natural gas reserves. We deducted when applicable,
operating costs, development costs and production-related and ad valorem taxes in arriving at the
estimated future cash flows. The following table presents our reserve information for the previous
two years. We base the estimates on operating methods and conditions prevailing as of the dates
indicated:
At December 31, | ||||||||
2009 | 2008 | |||||||
Natural gas reserves Proved Reserves (Mcf) (1)(4): |
||||||||
Proved developed reserves (2) |
32,799,000 | 48,760,500 | ||||||
Total proved reserves of natural gas |
32,799,000 | 48,760,500 | ||||||
Oil reserves Proved Reserves (Bbl) (1)(4): |
||||||||
Proved developed reserves (2) |
85,700 | 89,400 | ||||||
Total proved reserves of oil |
85,700 | 89,400 | ||||||
Total proved reserves (Mcfe) |
33,313,200 | 49,296,900 | ||||||
PV-10 estimate of cash flows of proved reserves (3)(4): |
||||||||
Proved developed reserves |
$ | 36,945,800 | $ | 84,897,100 | ||||
Total PV-10 estimate |
$ | 36,945,800 | $ | 84,897,100 | ||||
PV-10 estimate per limited partner unit (5) |
$ | 1,013 | $ | 2,387 | ||||
Undiscounted estimate per limited partner unit (5) |
$ | 1,909 | $ | 4,554 | ||||
(1) | Proved reserves generally refers to the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of the date the
estimate is made. Prices include consideration of changes in existing prices provided
only by contractual arrangements, but not on escalations based upon future conditions.
Reservoirs are considered proved if economic production is supported by either actual
production or conclusive formation test. The area of a reservoir considered proved
includes: that portion delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any, and the immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis of available geological and
engineering data. |
|
(2) | Proved developed reserves generally refers to reserves that can be expected to
be recovered through existing wells with existing equipment and operating methods. (Does
not include natural gas liquid reserves). |
|
(3) | The present value of estimated future net cash flows is calculated by discounting
estimated future net cash flows by 10% annually. |
|
(4) | Please see Regulation S-X rule 4-10 for complete definitions of each reserve
category. |
|
(5) | This value per $10,000 unit is determined by following the methodology used for
determining our proved reserves using the data discussed above. However, this value does
not necessarily reflect the fair market value of a unit, and each unit is illiquid.
Also, the value of a unit for purposes of presentment of the unit to our MGP for
purchase is different because it is calculated under a formula set forth in the
partnership agreement. |
We have not filed any estimates of our gas and oil reserves with, nor were such estimates
included in any reports to, any Federal or foreign governmental agency other than the SEC within
the 12 months before the date of this filing.
Title to Properties. We believe that we hold good and indefeasible title to our properties in
accordance with standards generally accepted in the natural gas industry, subject to exceptions
stated in the opinions of counsel employed by us in the various areas in which we conduct our
activities. We do not believe that these exceptions detract substantially from our use of any
property. As is customary in the natural gas industry, our MGP conducts only a perfunctory title
examination at the time it acquires a property. Before our MGP commences drilling operations, it
conducts an extensive title examination and performs curative work on defects that it deems
significant. Our MGP has obtained title examinations for substantially all of our producing
properties. No single property represents a material portion of our holdings.
Our properties are subject to royalty, overriding royalty and other outstanding interests
customary in the natural gas industry. Our properties are also subject to burdens such as liens
incident to operating agreements, taxes, development obligations under natural gas and oil leases,
farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that
any of these burdens will materially interfere with our use of our properties.
9
Acreage. The table below presents, by state, the estimated acres of developed and undeveloped
oil and gas acreage in which we had an interest at December 31, 2009. There was no undeveloped
acreage at December 31, 2009.
Developed Acreage | ||||||||
Location | Gross (1) | Net (2) | ||||||
Pennsylvania |
11,054.28 | 10,431.40 | ||||||
Tennessee |
2,930.50 | 2,618.67 | ||||||
Ohio |
52.27 | 21.84 | ||||||
Total |
14,037.05 | 13,071.91 | ||||||
(1) | A gross acre is an acre in which we own a working interest. |
|
(2) | A net acre represents the actual working interest we own in one gross acre
divided by one hundred. For example, a 50% working interest in an acre is one gross
acre, but a 0.5 net acre. |
|
(3) | Undeveloped acreage means those lease acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas regardless of whether or not the acreage contains proved
reserves. |
Delivery Commitments. Atlas Energy markets the remainder of our natural gas, which is
principally located in the Fayette County, PA area, primarily to Equitable Gas Interstate,
Interstate Gas Supply, Exelon Energy Company and Dominion Field Services and to other third-party
natural gas purchasers or marketers.
The pricing arrangements with Hess Corporation, UGI Energy Services, Inc. and other
third-party gas purchasers or marketers are tied to the New York Mercantile Exchange Commissions or
NYMEX spot market price. The total price received for our gas is a combination of the monthly NYMEX
spot price plus a basis adjustment. For example, the NYMEX spot price is the base price and there
is an additional premium paid, because of the location of the gas (the Appalachian Basin) in
relation to the gas market, which is referred to as the basis.
Pricing for natural gas and oil has been volatile and uncertain for many years. The agreements
with Hess Corporation, UGI Energy Services, Inc. and the other third-party gas purchasers or
marketers also permit Atlas Energy and its affiliates to implement gas forward sales transactions
through those companies. Hess Corporation, UGI Energy Services, Inc. and the other third-party
purchasers or marketers also use NYMEX based financial instruments to hedge their pricing exposure
and make price-hedging opportunities available to Atlas Energy, which then makes those arrangements
available to us and its other partnerships. The price paid by Hess Corporation, UGI Energy
Services, Inc. and any other third-party purchasers for certain volumes of natural gas sold under
these hedge agreements may be significantly different from the underlying monthly spot market
price. Also, Atlas Energys hedges may include purchases of regulated NYMEX futures and options
contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The
futures contracts employed by Atlas Energy are commitments to purchase or sell natural gas at
future dates and generally cover one-month periods for up to six years in the future. The overall
portion of our natural gas and oil portfolio that is hedged changes from time to time.
To assure that all financial instruments will be used solely for hedging price risks and not
for speculative purposes, Atlas Energy has established a committee to assure that all financial
trading is done in compliance with Atlas Energys hedging policies and procedures. Atlas Energy
does not intend to contract for positions that it cannot offset with actual production.
We are not required to provide any fixed and determinable quantities of gas under any
agreement other than with Hess Corporation, UGI Energy Services, Inc. and the other third-party gas
purchasers or marketers.
10
ITEM 3. | LEGAL PROCEEDINGS |
The MGP is not aware of any legal proceedings filed against us.
Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings
arising in the ordinary course of their collective business. The MGP management believes that none
of these actions, individually or in the aggregate, will have a material adverse effect on the
MGPs financial condition or results of operations.
ITEM 4. | (REMOVED AND RESERVED) |
None
PART II
ITEM 5. | MARKET FOR REGISTRANTS COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS |
Market Information. There is no established public trading market for our units and we do not
anticipate that a market for our units will develop. Our units may be transferred only in
accordance with the provisions of Article VI of our partnership agreement which requires:
| our MGP consent; |
||
| the transfer not result in materially adverse tax consequences to us; and |
||
| the transfer not violate federal or state securities laws. |
An assignee of a unit may become a substituted partner only upon meeting the following
conditions:
| the assignor gives the assignee the right; |
||
| our MGP consents to the substitution; |
||
| the assignee pays to us all costs and expenses incurred in connection with the
substitution; and |
||
| the assignee executes and delivers the instruments, which our MGP requires to effect
the substitution and to |
||
| confirm his or her agreement to be bound by the terms of our partnership agreement. |
A substitute partner is entitled to all of the rights of full ownership of the assigned units,
including the right to vote.
Holders. As of December 31, 2009, we had 5,080 unit holders.
Distributions. Our MGP reviews our accounts monthly to determine whether cash distributions
are appropriate and the amount to be distributed, if any. We distribute those funds, which our MGP
determines are not necessary for us to retain, to our partners. We will not advance or borrow funds
for purposes of making distributions.
The determination of our revenues and costs is made in accordance with generally accepted
accounting principles, consistently applied, and cash distributions to our MGP may only be made in
conjunction with distributions to our limited partners. There were no distributions made for the
year ended December 31, 2008.
During the year ended December 31, 2009, we distributed the following:
| $24,857,200 to our limited partners; and |
| $13,413,800 to our managing general partner. |
11
ITEM 7. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATIONS |
The following discussion provides information to assist in understanding our financial
condition and result of operations. This discussion should be read in conjunction with our
financial statements and related notes appearing elsewhere in this report.
General. We were formed as a Delaware limited partnership on May 7, 2007, with Atlas
Resources, LLC as our Managing General Partner, or MGP, to drill natural gas developmental wells.
Our MGPs is Atlas Resources, LLC, an indirect subsidiary Atlas Energy, Inc, (NASDAQ: ATLS) or
Atlas Energy. We have no current plans to sell any of our wells and will continue to produce them
until they are depleted or become uneconomical to produce, at which time they will be plugged and
abandoned or sold. No additional funds will be required for drillings.
Atlas Energys focus is on the development and production of natural gas and oil in the
Appalachian Basin, Michigan Basin and the Illinois Basin, regions of the United States of America.
Atlas Energy is also leading sponsor of and manages tax-advantaged direct investment partnerships,
in which it co-invests to finance the exploitation and development of its acreage. Atlas Energy
Resources, LLC is managed by Atlas Energy Management, Inc., through which Atlas Energy, Inc.
provides Atlas Energy Resources, LLC with the personnel necessary to manage its assets and raise
capital.
Results of Operations. The following table sets forth information related to our production
revenues, volumes, sales prices, production costs and depletion during the periods indicated:
Years Ended December 31, | ||||||||
2009 | 2008 | |||||||
Production revenues (in thousands): |
||||||||
Gas |
$ | 33,010 | $ | 22,697 | ||||
Oil |
1,360 | 835 | ||||||
Liquid |
5 | | ||||||
Total |
$ | 34,375 | $ | 23,532 | ||||
Production volumes: |
||||||||
Gas (mcf/day) (1) |
13,332 | 8,761 | ||||||
Oil (bbls/day) (1) |
71 | 32 | ||||||
Liquid (mcf/day (1) |
3 | | ||||||
Total (mcfe/day) (1) |
13,761 | 8,953 | ||||||
Average sales prices: (2) |
||||||||
Gas (per mcf) (1) (3) |
$ | 7.71 | $ | 9.19 | ||||
Oil (per bbl) (1) (4) |
$ | 58.89 | $ | 91.41 | ||||
Liquid (per mcf) (1) |
$ | 4.21 | $ | | ||||
Average production costs: |
||||||||
As a percent of revenues |
34 | % | 19 | % | ||||
Per mcfe (1) |
$ | 2.34 | $ | 1.81 | ||||
Depletion per mcfe |
$ | 3.24 | $ | 7.84 |
(1) | Mcf represents thousand cubic feet, mcfe represents thousand cubic feet
equivalent and bbls represents barrels. Bbls are converted to mcfe using the ratio of
six mcfs to one bbl. |
|
(2) | Average sales prices represent accrual basis pricing after reversing the effect
of previously recognized gains resulting from prior period impairment charges. |
|
(3) | Average gas prices are calculated by including in total revenue derivative gains
previously recognized into income and dividing by the total volume for the period.
Previously recognized derivative gains were $4,522,100 for the year ended December 31,
2009. The derivative gains are included in other comprehensive income and resulted from
prior period impairment charges. |
|
(4) | Average oil prices are calculated by including in total revenue derivative gains
previously recognized into income and dividing by the total volume for the period.
Previously recognized derivative gains were $168,100 for the year ended December 31,
2009. The derivative gains are included in other comprehensive income and resulted from
prior period impairment charges. |
12
Natural Gas Revenues. Our natural gas revenues were $33,010,500 and $22,696,800 for the
years ended December 31, 2009 and 2008, respectively, an increase of $10,313,700 (45%). The
$10,313,700 increase in natural gas revenues for the year ended December 31, 2009 as compared to
the prior year period was attributable to a $22,007,500 increase in production volumes, partially
offset by an $11,693,800 decrease in natural gas prices after the effect of financial hedge, which
were driven by market conditions. Our production volumes increased to 13,332 mcf per day for the
year ended December 31, 2009 from 8,761 mcf per day for the year ended December 31, 2008, an
increase of 4,571 (52%) mcf per day.
The price we receive for our natural gas is primarily a result of the index-driven agreements
with Hess Corporation, UGI Energy Services, Inc. and our other natural gas purchasers. See Item 2
Properties. Thus, the price we receive for our natural gas may vary significantly each month as
the underlying index changes in response to market conditions.
Oil Revenues. We drill wells primarily to produce natural gas, rather than oil, but some wells
have limited oil production. Our oil revenues were $1,360,000 and $835,000 for the years ended
December 31, 2009 and 2008, respectively, an increase of $525,000 (63%). The $525,000 increase in
oil revenues for the year ended December 31, 2009 as compared to the prior year period was
attributable to a $1,537,000 increase in production volumes, partially offset by a $1,012,000
decrease in oil prices after the effect of financial hedges. Our production volumes increased to 71
bbls per day for the year ended December 31, 2009 from 32 bbls per day for the year ended December
31, 2008, an increase of 39 bbls (122%) per day.
Natural Gas Liquids Revenue. The majority of our wells produce dry gas, which is composed
primarily of methane and requires no additional processing before being transported and sold to the
purchaser. Some wells, however, produce wet gas, which contains larger amounts of ethane and
other associated hydrocarbons (i.e. natural gas liquids) that must be removed prior to
transporting the gas. Once removed, these natural gas liquids are sold to various purchasers. Our
natural gas liquids revenues were $4,800 for the year ended December 31, 2009.
Expenses. Production expenses were $11,607,300 and $4,574,100 for the years ended December 31,
2009 and 2008, respectively, an increase of $7,033,200 (154%). This increase was primarily due to
higher transportation expenses, which were affected by an increase in production volumes.
Depletion of our oil and gas properties as a percentage of oil and gas revenues was 47% and
84% for the years ended December 31, 2009 and 2008, respectively. These percentage changes were
directly attributable to changes in revenues, oil and gas reserve quantities, product prices,
production volumes and changes in the depletable cost basis of oil and gas properties.
Impairment of oil and gas properties for the years ended December 31, 2009 and 2008 were
$5,791,800 and $117,588,900, respectively. Annually, we compare the carrying value of our proved
developed oil and gas producing properties to their estimated fair market value. To the extent our
carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a
result of this assessment, an impairment charge was recognized for the years ended December 31,
2009 and 2008. This charge is based on reserve quantities, future market values and our carrying
value. We cannot provide any assurance that similar charges may or may not be taken in future
periods.
General and administrative expenses were $538,300 for the year ended December 31, 2009 and
$133,700 for the year ended December 31, 2008, an increase of $404,600. These expenses include
third-party costs for services as well as the monthly administrative fees charged by our MGP and
vary from period to period due to the timing and billing of the costs and services provided to us.
This increase is due to more wells being on-line throughout the year.
13
Liquidity and Capital Resources. Cash provided by operating activities increased $23,993,900
in the year ended December 31, 2009 to $32,055,200 as compared to $8,061,300 for the year ended
December 31, 2008. This increase was primarily due to an increase in the change of a net-non cash
gain on derivative values of $11,685,500, accounts receivable-affiliate of $15,529,700 and accrued
liabilities of $483,800 partially offset by a decrease in net earnings before depletion, impairment
and accretion of $3,705,100.
Cash used in investing activities was $236,027,000 for the year ended December 31, 2008. This
was entirely due to well drilling fund paid to our MGP.
Cash used in financing activities was $38,271,000 for the year ended December 31, 2009. This
was entirely due to distributions to partners. Cash provided by financing activities was
$236,027,000 during the year ended December 31, 2008 consisted of funds contributed by the
investor partners for well drilling costs.
Our MGP may withhold funds for estimated future plugging and abandonment costs. Any additional
funds, if required, will be obtained from production revenues or borrowings from our MGP or its
affiliates, which are not contractually committed to make loans to us. The amount that we may
borrow may not at anytime exceed 5% of our total subscriptions, and we will not borrow from
third-parties.
We believe future cash flows from operations and amounts available from borrowings from our
MGP or its affiliates will be adequate to fund our operations.
Critical Accounting Policies. The preparation of financial statements in conformity with
accounting principles generally accepted in the United States requires making 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 actual
revenue and expenses during the reporting period. Although we base our estimates on historical
experience and various other assumptions that we believe to be reasonable under the circumstances,
actual results may differ from the estimates on which our financial statements are prepared at any
given point of time. Changes in these estimates could materially affect our financial position,
results of operations or cash flows. Significant items that are subject to such estimates and
assumptions include depletion and depreciation, asset impairment, fair value of derivative
instruments, and the probability of forecasted transactions. We summarize our significant
accounting policies within our financial statements included in Item 8, Financial Statements. The
critical accounting policies and estimates we have identified are discussed below.
Impairment of Long-Lived Assets. The cost of oil and gas properties, less estimated salvage
value, is depleted on the units-of-production method and is reviewed for impairment whenever events
or changes in circumstances indicate that the carrying amount of the assets may not be recoverable.
Events or changes in circumstances that would indicate the need for impairment testing include,
among other factors: operating losses; unused capacity; market value declines; technological
developments resulting in obsolescence; changes in demand for products manufactured by others
utilizing our services or for our products; changes in competition and competitive practices;
uncertainties associated with the United States and world economies; changes in the expected level
of environmental capital, operating or remediation expenditures; and changes in governmental
regulations or actions. During 2009 and 2008, we recognized an impairment charge of $5,791,800 and
$117,588,900 net of an offsetting gain in other comprehensive loss income of $574,400 and
$7,569,700, respectively.
14
Fair Value of Financial Instruments
We have established a hierarchy to measure our financial instruments at fair value which
requires us to maximize the use of observable inputs and minimize the use of unobservable inputs
when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure
fair value:
Level 1 Unadjusted quoted prices in active markets for identical, unrestricted assets and
liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 Inputs other than quoted prices included within Level 1 that are observable for the
asset and liability or can be corroborated with observable market data for substantially the entire
contractual term of the asset or liability.
Level 3 Unobservable inputs that reflect the entitys own assumptions about the assumption
market participants would use in the pricing of the asset or liability and are consequently not
based on market activity but rather through particular valuation techniques.
Our MGP uses a fair value methodology to value the assets and liabilities for our outstanding
derivative contracts. The commodity hedges are calculated based on observable market data related
to the change in price of the underlying commodity and are therefore defined as Level 2 fair value
measurements.
Assets and liabilities that are required to be measured at fair value on a nonrecurring basis
include our oil and gas properties and asset retirement obligations (AROs) that are defined as
Level 3. Estimates of the fair value of AROs are based on discounted cash flows using numerous
estimates, assumptions, and judgments regarding the cost, timing of settlement, our credit-adjusted
risk-free rate and inflation rates.
Reserve Estimates. Our estimates of proved natural gas and oil reserves and future net
revenues from them are based upon reserve analyses that rely upon various assumptions, including
those required by the SEC, as to natural gas and oil prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. Any significant variance in these
assumptions could materially affect the estimated quantity of our reserves. As a result, our
estimates of proved natural gas and oil reserves are inherently imprecise. Actual future
production, natural gas and oil prices, revenues, taxes, development expenditures, operating
expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our
estimates or estimates contained in the reserve reports and may affect partnership distributions.
In addition, our proved reserves may be subject to downward or upward revision based upon
production history, results of future development, prevailing natural gas and oil prices,
mechanical difficulties, governmental regulation and other factors, many of which are beyond our
control.
Asset Retirement Obligations. On an annual basis, we estimate the costs of future
dismantlement, restoration, reclamation and abandonment of our operating assets. We also estimate
the salvage value of equipment recoverable upon abandonment. Projecting future retirement cost
estimates is difficult as it involves the estimation of many variables such as economic recoveries
of reserves, future labor and equipment rates, future inflation rates and a credit adjusted risk
free rate. To the extent future revisions to these assumptions impact the fair value of our
existing asset retirement obligation, a corresponding adjustment is made to our oil and gas
properties. A decrease in salvage values or an increase in dismantlement, restoration, reclamation
and abandonment costs from those we and our subsidiaries have estimated, or changes in their
estimates or costs, could reduce our gross profit from operations.
Working Interest. Our agreement establishes that revenues and expensed will be allocated to
our MGP and limited partners based on their ratio of capital contributions to total contributions.
(working interest). Our MGP is also provided an additional working interest of 7% as provided in
our agreement. Due to the time necessary to complete drilling operations and accumulate all
drilling costs, estimated working interest percentage ownership rates are utilized to allocated
revenues and expenses until the wells are completely drilled and turned on-line into production.
Once the wells are completed, the final working interest ownership of the partners is determined
and any previously allocated revenues and expenses based on the estimated working interest
percentage ownership are adjusted to conform to the final working interest percentage ownership. As
of December 31, 2009, $3,243,400 of net earnings resulting from the working interest adjustment was
reclassified from the MGPs capital account to the limited partners capital account.
15
ITEM 8. | FINANCIAL STATEMENTS |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of
Atlas Resources Public #17-2008 (B) L.P.
Atlas Resources Public #17-2008 (B) L.P.
We have audited the accompanying balance sheets of Atlas Resources Public #17-2008 (B) L.P. (a
Delaware Limited Partnership) as of December 31, 2009 and 2008, and the related statements of
operations, comprehensive loss, changes in partners capital, and cash flows for the years then
ended. These financial statements are the responsibility of the Partnerships management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. The
Partnership is not required to have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion on the effectiveness of the
Partnerships internal control over financial reporting. Accordingly, we express no such opinion.
An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements, 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 financial statements referred to above present fairly, in all material
respects, the financial position of Atlas Resources Public #17-2008 (B) L.P. as of December 31,
2009 and 2008, and the results of its operations and its cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of America.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
March 30, 2010
March 30, 2010
16
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
BALANCE SHEETS
DECEMBER 31,
BALANCE SHEETS
DECEMBER 31,
2009 | 2008 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 1,845,500 | $ | 8,061,300 | ||||
Accounts receivable affiliate |
6,009,300 | 10,769,500 | ||||||
Short-term hedge receivable due from affiliate |
4,108,000 | 10,597,700 | ||||||
Total current assets |
11,962,800 | 29,428,500 | ||||||
Oil and gas properties, net |
139,687,000 | 142,517,100 | ||||||
Construction in progress |
| 4,840,000 | ||||||
Long-term hedge liability due from affiliate |
3,375,500 | 6,787,000 | ||||||
$ | 155,025,300 | $ | 183,572,600 | |||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
Current liabilities: |
||||||||
Accrued liabilities |
$ | 494,200 | $ | 5,200 | ||||
Short-term hedge liability due to affiliate |
49,100 | 924,300 | ||||||
Total current liabilities |
543,300 | 929,500 | ||||||
Asset retirement obligation |
4,536,000 | 3,298,000 | ||||||
Long-term hedge liability due to affiliate |
526,600 | 831,500 | ||||||
Partners capital: |
||||||||
Managing general partner |
37,920,400 | 37,298,200 | ||||||
Limited partners (23,644.10 units) |
108,045,100 | 133,156,200 | ||||||
Accumulated other comprehensive income |
3,453,900 | 8,059,200 | ||||||
Total partners capital |
149,419,400 | 178,513,600 | ||||||
$ | 155,025,300 | $ | 183,572,600 | |||||
The accompanying notes are an integral part of these financial statements.
17
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2009 AND 2008
STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2009 AND 2008
2009 | 2008 | |||||||
REVENUES |
||||||||
Natural gas, oil and liquid gas |
$ | 34,375,300 | $ | 23,531,800 | ||||
Interest |
6,500 | 1,600 | ||||||
Total revenues |
34,381,800 | 23,533,400 | ||||||
COST AND EXPENSES |
||||||||
Production |
11,727,700 | 4,574,100 | ||||||
Depletion |
16,270,100 | 19,806,600 | ||||||
Impairment of oil and gas properties |
5,791,800 | 117,588,900 | ||||||
Accretion of asset retirement obligations |
197,900 | 167,500 | ||||||
General and administrative |
538,300 | 133,700 | ||||||
Total expenses |
34,525,800 | 142,270,800 | ||||||
Net loss |
$ | (144,000 | ) | $ | (118,737,400 | ) | ||
Allocation of net earnings (loss): |
||||||||
Managing general partner |
$ | 3,353,300 | $ | (15,866,600 | ) | |||
Limited partners |
$ | (3,497,300 | ) | $ | (102,870,800 | ) | ||
Net loss per limited partnership unit |
$ | (148 | ) | $ | (4,351 | ) | ||
The accompanying notes are an integral part of these financial statements.
18
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
STATEMENTS OF COMPREHENSIVE LOSS
YEARS ENDED DECEMBER 31, 2009 AND 2008
STATEMENTS OF COMPREHENSIVE LOSS
YEARS ENDED DECEMBER 31, 2009 AND 2008
2009 | 2008 | |||||||
Net loss |
$ | (144,000 | ) | $ | (118,737,400 | ) | ||
Other comprehensive income (loss): |
||||||||
Unrealized holding gain on hedging contracts |
4,821,700 | 7,364,400 | ||||||
Less: reclassification adjustment for (gains) loss realized in net earnings |
(9,427,000 | ) | 694,800 | |||||
Total comprehensive (loss) income |
(4,605,300 | ) | 8,059,200 | |||||
Comprehensive loss |
$ | (4,749,300 | ) | $ | (110,678,200 | ) | ||
The accompanying notes are an integral part of these financial statements.
19
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
STATEMENTS OF CHANGES IN PARTNERS CAPITAL
YEARS ENDED DECEMBER 31, 2009 AND 2008
STATEMENTS OF CHANGES IN PARTNERS CAPITAL
YEARS ENDED DECEMBER 31, 2009 AND 2008
Accumulated | ||||||||||||||||
Managing | other | |||||||||||||||
General | Limited | Comprehensive | ||||||||||||||
Partner | Partners | Income (loss) | Total | |||||||||||||
Balance at December 31, 2007 |
$ | | $ | | $ | | $ | | ||||||||
Partners capital contributions: |
||||||||||||||||
Cash |
100 | 236,027,000 | | 236,027,100 | ||||||||||||
Syndication and offering costs |
25,021,500 | | | 25,021,500 | ||||||||||||
Tangible equipment/leasehold costs |
53,164,700 | | | 53,164,700 | ||||||||||||
Total contributions |
78,186,300 | 236,027,000 | | 314,213,300 | ||||||||||||
Syndication and offering costs, immediately
charged to capital |
(25,021,500 | ) | | | (25,021,500 | ) | ||||||||||
53,164,800 | 236,027,000 | | 289,191,800 | |||||||||||||
Participation in revenue and expenses: |
||||||||||||||||
Net production revenues |
6,352,700 | 12,605,000 | | 18,957,700 | ||||||||||||
Interest |
500 | 1,100 | | 1,600 | ||||||||||||
Depletion |
(3,188,600 | ) | (16,618,000 | ) | | (19,806,600 | ) | |||||||||
Impairment of oil and gas properties |
(18,930,300 | ) | (98,658,600 | ) | | (117,588,900 | ) | |||||||||
General and administrative |
(44,800 | ) | (88,900 | ) | | (133,700 | ) | |||||||||
Accretion of asset retirement obligations |
(56,100 | ) | (111,400 | ) | | (167,500 | ) | |||||||||
Net loss |
(15,866,600 | ) | (102,870,800 | ) | | (118,737,400 | ) | |||||||||
Other comprehensive income |
| | 8,059,200 | 8,059,200 | ||||||||||||
Balance at December 31, 2008 |
$ | 37,298,200 | $ | 133,156,200 | $ | 8,059,200 | $ | 178,513,600 | ||||||||
Partners capital contributions: |
||||||||||||||||
Syndication and offering costs adjustment |
(587,800 | ) | | | (587,800 | ) | ||||||||||
Total contributions |
(587,800 | ) | | | (587,800 | ) | ||||||||||
Syndication and offering costs adjustment,
immediately charged to capital |
587,800 | | | 587,800 | ||||||||||||
| | | | |||||||||||||
Participation in revenue and expenses: |
||||||||||||||||
Net production revenues |
7,965,200 | 14,682,400 | | 22,647,600 | ||||||||||||
Interest |
2,300 | 4,200 | | 6,500 | ||||||||||||
Depletion |
(3,211,900 | ) | (13,058,200 | ) | | (16,270,100 | ) | |||||||||
Impairment of oil and gas properties |
(1,143,300 | ) | (4,648,500 | ) | | (5,791,800 | ) | |||||||||
General and administrative |
(189,400 | ) | (348,900 | ) | | (538,300 | ) | |||||||||
Accretion of asset retirement obligations |
(69,600 | ) | (128,300 | ) | | (197,900 | ) | |||||||||
Net earnings (loss) |
3,353,300 | (3,497,300 | ) | | (144,000 | ) | ||||||||||
Other comprehensive loss |
| | (4,605,300 | ) | (4,605,300 | ) | ||||||||||
Working interest adjustment |
(3,243,400 | ) | 3,243,400 | | | |||||||||||
Asset contributions |
13,926,100 | | | 13,926,100 | ||||||||||||
Distributions to partners |
(13,413,800 | ) | (24,857,200 | ) | | (38,271,000 | ) | |||||||||
Balance at December 31, 2009 |
$ | 37,920,400 | $ | 108,045,100 | $ | 3,453,900 | $ | 149,419,400 | ||||||||
The accompanying notes are an integral part of these financial statements.
20
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2009 AND 2008
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2009 AND 2008
2009 | 2008 | |||||||
Cash flows from operating activities: |
||||||||
Net loss |
$ | (144,000 | ) | $ | (118,737,400 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating
activities: |
||||||||
Depletion |
16,270,100 | 19,806,600 | ||||||
Non-cash loss (gain) on derivative |
4,115,800 | (7,569,700 | ) | |||||
Impairment of oil and gas properties |
6,366,200 | 125,158,600 | ||||||
Accretion of asset retirement obligation |
197,900 | 167,500 | ||||||
Decrease (increase) in accounts receivable-affiliate |
4,760,200 | (10,769,500 | ) | |||||
Increase in accrued liabilities |
489,000 | 5,200 | ||||||
Net cash provided by operating activities |
32,055,200 | 8,061,300 | ||||||
Cash flows from investing activities: |
||||||||
Oil and gas well drilling contracts paid to MGP |
| (236,027,000 | ) | |||||
Net cash used in investing activities |
| (236,027,000 | ) | |||||
Cash flows from financing activities: |
||||||||
Partners capital contributions |
| 236,027,000 | ||||||
Distribution to partners |
(38,271,000 | ) | | |||||
Net cash (used in) provided by financing activities |
(38,271,000 | ) | 236,027,000 | |||||
Net (decrease) increase in cash and cash equivalents |
(6,215,800 | ) | 8,061,300 | |||||
Cash and cash equivalents at beginning of period |
8,061,300 | | ||||||
Cash and cash equivalents at end of period |
$ | 1,845,500 | $ | 8,061,300 | ||||
Supplemental Schedule of non-cash investing and financing activities: |
||||||||
Assets (returned to) contributed by the managing general partner: |
||||||||
Tangible equipment |
$ | 7,452,200 | $ | 47,798,100 | ||||
Lease costs |
| 5,366,700 | ||||||
Intangible drillings costs |
6,473,900 | | ||||||
Syndication and offering costs |
(587,800 | ) | 25,021,500 | |||||
$ | 13,338,300 | $ | 78,186,300 | |||||
Asset retirement obligation |
$ | 1,040,100 | $ | 3,130,500 | ||||
The accompanying notes are an integral part of these financial statements.
21
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2009 AND 2008
NOTE 1 DESCRIPTION OF BUSINESS
Atlas Resources Public 17-2008 (B) L.P. (the Partnership) is a Delaware Limited Partnership,
which includes Atlas Resources, LLC of Pittsburgh, Pennsylvania, as Managing General Partner
(MGP) and Operator, and 5,079 Limited Partners. The Partnership was formed on May 7, 2007 to
drill and operate gas wells located in Pennsylvania, Tennessee and Ohio.
In March 2006, Atlas Resources, Inc. merged into a newly-formed limited liability company,
Atlas Resources, LLC, which became an indirect subsidiary of Atlas Energy Resources, LLC, a
newly-formed subsidiary of Atlas America, Inc. In December 2006, Atlas America, Inc. contributed
substantially all of its natural gas and oil assets and its investment partnership management
business to Atlas Energy Resources, LLC. On September 29, 2009 Atlas Energy Resources, LLC and
Atlas America, Inc. merged, with Atlas Energy Resources, LLC becoming a wholly owned subsidiary of
Atlas America, Inc. In addition, Atlas America, Inc. changed its name to Atlas Energy, Inc,
(NASDAQ: ATLS). Atlas Resources, LLC serves as the Partnerships MGP.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A summary of significant accounting policies applied in the preparation of the accompanying
financial statements follows:
Use of Estimates
The preparation of the Partnerships financial statements in conformity with accounting
principles generally accepted in the United States requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities that exist at the date of the Partnerships financial statements, as well as
the reported amounts of revenue and costs and expenses during the reporting periods. The
Partnerships financial statements are based on a number of significant estimates, including the
revenue and expense accruals, depletion, asset impairments, fair value of derivative instruments,
and the probability of forecasted transactions. Actual results could differ from those estimates.
Accounts Receivable and Allowance for Possible Losses
In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit
evaluations of its customers and adjusts credit limits based upon payment history and the
purchasers current creditworthiness, as determined by review of its customers credit information.
Credit is extended on an unsecured basis to many of its energy customers. At December 31, 2009 and
2008, the Partnerships MGPs credit evaluation indicated that the Partnership had no need for an
allowance for possible losses.
Revenue Recognition
The Partnerships natural gas and oil is sold under various contracts entered into by its MGP.
The Partnership generally sells natural gas and crude oil at prevailing market prices. Revenue is
recognized when produced quantities are delivered to a custody transfer point, persuasive evidence
of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser
upon delivery, collection of revenue from the sale is reasonably assured and the sales price is
fixed or determinable. Revenues from the production of natural gas and crude oil in which the
Partnership has an interest with other producers are recognized on the basis of the Partnerships
percentage ownership of working interest. Generally, the MGPs sales contracts are based on pricing
provisions that are tied to a market index, with certain adjustments based on proximity to
gathering and transmission lines and the quality of its natural gas.
22
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Because there are timing differences between the delivery of the Partnerships natural gas and
oil and its receipt of a delivery statement, the Partnership has unbilled revenues. These revenues
are accrued based on volumetric data from its records and its estimates of the related
transportation and compression fees, which are, in turn, based on applicable product prices. The
Partnership had unbilled trade receivables of $4,230,500 and $8,029,100 at December 31, 2009 and
2008, respectively, which are included in Accounts receivable affiliate on the Partnerships
Balance Sheet.
Fair Value of Financial Instruments
The carrying amounts of the Partnerships cash and receivable approximate fair values because
of the short maturities of these instruments.
Supplemental Cash Flow Information
The Partnership considers temporary investments with a maturity at the date of acquisition of
90 days or less to be cash equivalents. No cash was paid by the Partnership for interest or income
taxes for the years ended December 31, 2009 and 2008.
Concentration of Credit Risk
Financial instruments, which potentially subject the Partnership to concentrations of credit
risk, consist principally of periodic temporary investments of cash and cash equivalents. The
Partnership places its temporary cash investments in deposits with high-quality financial
institutions. At December 31, 2009, the Partnership had $1,939,700 in deposits at one bank of which
$1,689,700 was over the insurance limit of the Federal Deposit Insurance Corporation and at
December 31, 2008, the Partnership had $8,066,100 in deposits at one bank of which $7,816,100 was
over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been
experienced on such investments.
Comprehensive Loss
Comprehensive loss includes net loss and all other changes in equity of a business during a
period from transactions and other events and circumstances from non-owner sources that, under
accounting principles generally accepted in the United States, have not been recognized in the
calculation of net income. These changes, other than net loss, are referred to as other
comprehensive loss and, for the Partnership, include changes in the fair value of unsettled
derivative contracts accounted for as cash flow hedges.
Working Interest
The Partnership agreement establishes that revenues and expenses will be allocated to the MGP
and limited partners based on their ratio of capital contributions to total contributions,
(working interest). The MGP is also provided an additional working interest of 7% as provided in
the Partnership agreement. Due to the time necessary to complete drilling operations and accumulate
all drilling costs, estimated working interest percentage ownership rates are utilized to allocate
net revenues and expenses until the wells are completely drilled and turned on-line into
production. Once the wells are completed, the final working interest ownership of the partners is
determined and any previously allocated revenues based on the estimated working interest percentage
ownership are adjusted to conform to the final working interest percentage ownership. As of
December 31, 2009, $3,243,400 of net earnings resulting from the working interest adjustment was
reclassified from the MGPs capital account to the limited partners capital account.
23
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Oil and Gas Properties
The Partnership follows the successful-efforts method of accounting for oil and gas producing
activities. Oil and gas properties are recorded at cost. Depletion is determined on a
field-by-field basis using the units-of-production method for well and related equipment costs
based on proved developed reserves associated with each field. Depletion rates are determined based
on reserve quantity estimates and the capitalized costs of developed producing properties. In
addition, accumulated depletion includes impairment adjustments to reflect the write-down to fair
market value of the oil and gas properties. Maintenance and repairs are expensed as incurred. Major
renewals and improvements that extend the useful lives of the property are capitalized. The
Partnership is required to consider estimated salvage value in the calculation of depletion.
Oil and gas properties consist of the following at the dates indicated:
December 31, | ||||||||
2009 | 2008 | |||||||
Proved properties: |
||||||||
Leasehold interests |
$ | 5,366,700 | $ | 5,366,700 | ||||
Wells and related equipment |
301,921,800 | 282,115,600 | ||||||
307,288,500 | 287,482,300 | |||||||
Accumulated depletion |
(167,601,500 | ) | (144,965,200 | ) | ||||
$ | 139,687,000 | $ | 142,517,100 | |||||
The Partnerships long-lived assets are reviewed for impairment at least annually or whenever
events or changes in circumstances indicate that the carrying amount of an asset may not be
recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for
which there are identifiable cash flows. The review is done by determining if the historical cost
of proved properties less the applicable accumulated depletion and salvage value is less than the
estimated expected undiscounted future cash flows. The expected future cash flows are estimated
based on the Partnerships plans to continue to produce and develop proved reserves. The
determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of
any reserve estimate depends on the quality of available data and the application of engineering
and geological interpretation and judgment. Estimates of economically recoverable reserves and
future net cash flows depend on a number of variable factors and assumptions that are difficult to
predict and may vary considerably from actual results. If the carrying value exceeds such
undiscounted cash flows, an impairment loss is recognized for the difference between the estimated
fair market value and the carrying value of the assets. The fair market value is determined as the
present value of future net revenues from the production of proved reserves discounted using an
annual discount rate of 12% in 2009 and 2008. During the years ended December 31, 2009 and 2008,
the Partnership recognized an impairment charge of $5,791,800 and $117,588,900, respectively, net
of an offsetting gain in other comprehensive income of $574,400 and $7,569,700, respectively.
Upon the sale or retirement of a complete or partial unit of a proved property, the cost is
eliminated from the property accounts, and the resultant gain or loss is reclassified to
accumulated depletion. Upon the sale of an entire interest where the property had been assessed for
impairment, a gain or loss is recognized in the Statement of Operations.
24
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Asset Retirement Obligation
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil
and gas wells and related facilities, or asset retirement obligations (see Note 9). The Partnership
recognizes a liability for future asset retirement obligations in the current period if a
reasonable estimate of the fair value of the liability can be made. The associated asset retirement
costs are capitalized as part of the carrying amount of the long-lived asset.
Environmental Matters
The Partnership is subject to various federal, state and local laws and regulations relating
to the protection of the environment. The Partnership has established procedures for the ongoing
evaluation of its operations, to identify potential environmental exposures and to comply with
regulatory policies and procedures.
Environmental expenditures that relate to current operations are expensed or capitalized as
appropriate. Expenditures that relate to an existing condition caused by past operations, and do
not contribute to current or future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated.
Atlas Energy maintains insurance that may cover in whole or in part certain environmental
expenditures. For the years ended December 31, 2009 and 2008, the Partnership had no environmental
matters requiring specific disclosure or the recording of a liability.
Major Customers
The Partnerships natural gas is sold under contract to various purchasers. For the year ended
December 31, 2009, sales to Equitable Gas accounted for 27% of total revenues. For the year ended
December 31, 2008, sales to Equitable Gas and Hess Corporation, accounted for 33% and 22%,
respectively. No other customers accounted for 10% or more of total revenues for the years ended
December 31, 2009 and 2008.
Income Taxes
The Partnership is not treated as a taxable entity for federal income tax purposes. Any item
of income, gain, loss, deduction or credit flows through to the partners as though each partner had
incurred such item directly. As a result, each partner must take into account their pro rata share
of all items of partnership income and deductions in computing their federal income tax liability.
25
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Adopted Accounting Standards
In February 2010, the Financial Accounting Standards Board (FASB) issued Accounting
Standards Update 2010-09 Amendments to Certain Recognition and Disclosure Requirements (Update
2010-09). Update 2010-09 amends Accounting Standards Codification (ASC) 855-10-50-1 to clarify
that all entities other than SEC filers must disclose (1) the date through, which subsequent events
have been evaluated and (2) whether that date is the date the financial statements were issued or
available to be issued. However, the date-disclosure exemption for SEC filers does not relieve
management from its responsibility to evaluate subsequent events through the date on which
financial statements are issued. The Partnership adopted the requirements of Update 2010-09 on
December 31, 2009, and it did not have a material impact on its financial position, results of
operations or related disclosures.
In January 2010, the FASB issued Accounting Standards Update 2010-03, Extractive Activities
Oil and Gas (Topic 932) Oil and Gas Reserve Estimation and Disclosures (Update 2010-03).
Update 2010-03 includes amendments to ASC Topic 932 Extractive Activities Oil and Gas, to
include within the ASC the reporting requirements covered in the Securities and Exchange
Commissions (SEC) final rule, Modernization of Oil and Gas Reporting issued on December 31,
2008. The Partnership adopted the requirements of Update 2010-03 on December 31, 2009. These new
disclosure requirements include provisions that:
| Introduce a new definition of oil and gas producing activities. This new definition
allows companies to include in their reserve base volumes from unconventional resources. Such
unconventional resources include bitumen extracted from oil sands and oil and gas extracted from
coal beds and shale formations; |
||
| Report oil and gas reserves using an unweighted average price using the prior 12-month
period, based on the closing prices on the first day of each month, rather than year-end pricing.
This should maximize the comparability of reserve estimates among companies and mitigate the
distortion of the estimates that arises when using a single pricing date; |
||
| Permit companies to disclose their probable and possible reserves on a voluntary basis.
Current rules limit disclosure to only proved reserves; |
||
| Update and revise reserve definitions to reflect changes in the oil and gas industry and
new technologies. New updated definitions include by geographic area and reasonable certainty; |
||
| Permit the use of new technologies to determine proved reserves if those technologies
have been demonstrated empirically to lead to reliable conclusions about reserves volumes; and |
||
| Require additional disclosures regarding the qualifications of the chief technical
person who oversees the companys overall reserve estimation process. Additionally, disclosures are
required with regard to internal controls over reserve estimation, as well as a report addressing
the independence and qualifications of a companys reserves preparer or auditor based on Society of
Petroleum Engineers criteria. |
The Partnership has complied with the disclosure requirements for the year ended December 31,
2009.
26
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Adopted Accounting Standards (Continued)
In August 2009, the FASB issued Accounting Standards Update 2009-05, Fair Value Measurements
and Disclosures (Topic 820) Measuring Liabilities at Fair Value (Update 2009-05). Update
2009-05 amends Subtopic 820-10, Fair Value Measurements and Disclosures Overall and provides
clarification for the fair value measurement of liabilities in circumstances where quoted prices
for an identical liability in an active market are not available. The amendments also provide
clarification for not requiring the reporting entity to include separate inputs or adjustments to
other inputs relating to the existence of a restriction that prevents the transfer of a liability
when estimating the fair value of a liability. Additionally, these amendments clarify that both the
quoted price in an active market for an identical liability at the measurement date and the quoted
price for an identical liability when traded as an asset in an active market when no adjustments to
the quoted price of the asset are required are considered Level 1 fair value measurements. These
requirements are effective for financial statements issued after the release of Update 2009-05. The
Partnership adopted the requirements of Update 2009-05 on September 30, 2009, and it did not have a
material impact on its financial position, results of operations or related disclosures.
In June 2009, the FASB issued Accounting Standards Update 2009-01, Topic 105 Generally
Acceptable Accounting Principles Amendments Based on Statement of Financial Accounting Standards
No. 168 The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted
Accounting Principles (Update 2009-01). Update 2009-01 establishes the FASB ASC as the single
source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be
applied by nongovernmental entities. The ASC supersedes all existing non-Securities and Exchange
Commission accounting and reporting standards. Following the ASC, the FASB will not issue new
standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts.
Instead, the FASB will issue Accounting Standards Updates, which will serve only to update the ASC.
The ASC is effective for financial statements issued for interim and annual periods ending after
September 15, 2009. All required references to non-SEC accounting standards have been modified by
the Partnership. The Partnership adopted the requirements of Update 2009-01 for its financial
statements on September 30, 2009, and it did not have a material impact on its financial statement
disclosures.
In May 2009, the FASB issued ASC 855-10, Subsequent Events (ASC 855-10). ASC 855-10
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. The
provisions require management of a reporting entity to evaluate events or transactions that may
occur after the balance sheet date for potential recognition or disclosure in the financial
statements and provides guidance for disclosures that an entity should make about those events. ASC
855-10 is effective for interim or annual financial periods ending after June 15, 2009 and shall be
applied prospectively. The Partnership adopted the requirements of this standard on June 30, 2009,
and it did not have a material impact on its financial position or results of operations or related
disclosures. The adoption of these provisions does not change the Partnerships current practices
with respect to evaluating, recording and disclosing subsequent events.
In April 2009, the FASB issued ASC 820-10-65-4, Determining Fair Value When the Volume and
Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly (ASC 820-10-65-4). ASC 820-10-65-4 applies to all fair value
measurements and provides additional clarification on estimating fair value when the market
activity for an asset has declined significantly. ASC 820-10-65-4 also require an entity to
disclose a change in valuation technique and related inputs to the valuation calculation and to
quantify its effects, if practicable. ASC 820-10-65-4 is effective for interim and annual periods
ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.
The Partnership adopted the requirements of ASC 820-10-65-4 on April 1, 2009, and its adoption did
not have a material impact on its financial position and results of operations.
27
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Recently Adopted Accounting Standards (Continued)
In April 2009, the FASB issued ASC 825-10-65-1, Interim Disclosures about Fair Value of
Financial Instruments (ASC 825-10-65-1), which requires an entity to provide disclosures about
fair value of financial instruments in interim financial information. In addition, an entity shall
disclose in the body or in the accompanying notes of its summarized financial information for
interim reporting periods and in its financial statements for annual reporting periods the fair
value of all financial instruments for which it is practicable to estimate that value, whether
recognized or not recognized in the statement of financial position. ASC 825-10-65-1 is effective
for interim periods ending after June 15, 2009, with early adoption permitted for periods ending
after March 15, 2009. The Partnership adopted these requirements on April 1, 2009, and its adoption
did not have a material impact on its financial position and results of operations.
In March 2008, the FASB issued ASC 815-10-50-1, Disclosures about Derivative Instruments and
Hedging Activities (ASC 815-10-50-1), to require enhanced disclosure about how and why an entity
uses derivative instruments, how derivative instruments and related hedged items are accounted for
and how derivative instruments and related hedged items affect an entitys financial position,
financial performance and cash flows. The Partnership adopted the requirements of this section of
ASC 815-10-50-1 on January 1, 2009, and it did not have a material impact on its financial position
or results of operations (see Note 7).
NOTE 3 PARTICIPATION IN REVENUES AND COSTS
The MGP and the other partners will generally participate in revenues and costs in the
following manner:
Managing | ||||||||
General | Limited | |||||||
Partner | Partners | |||||||
Organization and offering costs |
100 | % | 0 | % | ||||
Lease costs |
100 | % | 0 | % | ||||
Revenues (1) |
35.17 | % | 64.83 | % | ||||
Operating costs, administrative costs, direct costs and all other operating costs (2) |
35.17 | % | 64.83 | % | ||||
Intangible drilling costs |
3.22 | % | 96.78 | % | ||||
Tangible equipment costs |
82.02 | % | 17.98 | % |
(1) | Subject to the MGPs subordination obligation, substantially all partnership
revenues will be shared in the same percentage as capital contributions are to the
total partnership capital contributions, except that the MGP will receive an additional
7% of the partnership revenues. The MGP revenue percentage may not exceed 40%. |
|
(2) | These costs will be charged to the partners in the same ratio as the related
production revenues are credited. |
28
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 4 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Partnership has entered into the following significant transactions with its MGP and its
affiliates as provided under the Partnership agreement. The MGP and its affiliates perform all
administrative and management functions for the Partnership including billing revenues and paying
expenses. The line-item Accounts receivable-affiliate on the Partnerships Balance Sheets
represents the net production revenues due from the MGP.
| Drilling contracts to drill and complete wells for the Partnership are charged at cost
plus 15%. The cost of the wells includes reimbursement to the Partnerships MGP of its
general and administrative overhead cost and all ordinary and actual costs of drilling,
testing and completing the wells. The Partnership paid $236,027,000 to the MGP in 2008 to
drill the wells. |
| The Partnerships MGP contributed undeveloped leases necessary to cover each of the
Partnerships prospects and as of December 31, 2008 received a credit to its capital
account in the Partnership of $5,366,700. |
| Administrative costs which are included in general and administrative expenses in the
Partnerships Statement of Operations are payable at $75 per well, per month.
Administrative costs incurred in 2009 and 2008 were $364,800 and $95,500, respectively. |
| Monthly well supervision fees which are included in production expenses in the
Partnerships Statement of Operations are payable at $377 per well, per month for operating
and maintaining the wells. Well supervision fees incurred in 2009 and 2008 were $1,833,500
and $480,100, respectively. |
| Transportation fees which are included in production expenses in the Partnerships
Statement of Operations are generally payable at 13% of the natural gas sales price.
Transportation fees incurred in 2009 and 2008 were $4,851,700 and $2,956,700, respectively. |
| Direct costs which are included in production and general administrative expenses in the
Partnerships Statement of Operations are payable to the MGP and its affiliates as
reimbursement for all costs expended on the Partnerships behalf. Direct costs incurred in
2009 and 2008 were $5,216,000 and $1,175,500, respectively. |
| Assets contributed to the MGP which are disclosed on the Partnerships Statements of
Cash Flows as a non-cash investing activity for the years ended December 31, 2009 and 2008
were $13,338,300 and $78,186,300, respectively. |
NOTE 5 COMMITMENTS
Subject to certain conditions, investor partners may present their interests beginning in 2013
for purchase by the MGP. The purchase price is calculated by the MGP in accordance with the terms
of the partnership agreement. The MGP is not obligated to purchase more than 5% of the units in any
calendar year. In the event that the MGP is unable to obtain the necessary funds, it may suspend
its purchase obligation.
Beginning one year after each of the Partnerships wells has been placed into production, the
MGP, as operator, may retain $200 per month per well to cover estimated future plugging and
abandonment costs. As of December 31, 2009, the MGP has not withheld any such funds.
29
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 6 SUBORDINATION BY MANAGING GENERAL PARTNER
Under the terms of the Partnership agreement, the MGP may be required to subordinate up to 50%
of its share of net production revenues of the Partnership to provide a distribution to the
investor partners equal to at least 10% of their agreed subscriptions. Subordination is determined
on a cumulative basis, in each of the first five years of Partnership operations, commencing with
the first distribution of net revenues to the investor partners (February 2009). Since the
inception of the program, the MGP has not been required to subordinate any of its distributions to
its limited partners.
NOTE 7 DERIVATIVE INSTRUMENTS
The MGP on behalf of the Partnership uses a number of different derivative instruments,
principally swaps and collars, in connection with its commodity price risk management activities.
The MGP enters into financial instruments to hedge the Partnerships forecasted natural gas, crude
oil and condensate against the variability in expected future cash flows attributable to changes in
market prices. Swap instruments are contractual agreements between counterparties to exchange
obligations of money as the underlying natural gas, and crude oil is sold. Under swap agreements,
the Partnership receives or pays a fixed price and receives or remits a floating price based on
certain indices for the relevant contract period. Commodity-based option instruments are
contractual agreements that grant the right, but not obligation, to purchase or sell natural gas,
and crude oil at a fixed price for the relevant contract period.
The MGP formally documents all relationships between hedging instruments and the items being
hedged, including its risk management objective and strategy for undertaking the hedging
transactions. This includes matching the commodity derivative contracts to the forecasted
transactions. The MGP assesses, both at the inception of the derivative and on an ongoing basis,
whether the derivative is effective in offsetting changes in the forecasted cash flow of the hedged
item. If it is determined that a derivative is not effective as a hedge or that it has ceased to be
an effective hedge due to the loss of adequate correlation between the hedging instrument and the
underlying item being hedged, the Partnership will discontinue hedge accounting for the derivative
and subsequent changes in the derivative fair value, which is determined by the MGP through the
utilization of market data, will be recognized immediately within gain (loss) on mark-to-market
derivatives in the Partnerships statements of operations. For derivatives qualifying as hedges,
the Partnership recognizes the effective portion of changes in fair value in partners capital as
accumulated other comprehensive loss and will reclassify commodity derivatives to gas and oil
production revenues in the Partnerships Statements of Operations as the underlying transactions
are settled. For non-qualifying derivatives and for the ineffective portion of qualifying
derivatives, the Partnership recognizes changes in fair value within gain (loss) on mark-to-market
derivatives in its statements of operations as they occur. The following table summarizes the fair
value of derivative instruments as of December 31, 2009 and 2008.
Fair Value of Derivative Instruments:
Asset Derivatives | Liability Derivatives | |||||||||||||||||||
Derivatives in | Fair Value | Fair Value | ||||||||||||||||||
Cash Flow | Balance Sheet | December 31, | December 31, | Balance Sheet | December 31, | December 31, | ||||||||||||||
Hedging Relationships | Location | 2009 | 2008 | Location | 2009 | 2008 | ||||||||||||||
Commodity contracts: |
Current assets | $ | 4,108,000 | $ | 10,597,700 | Current liabilities | $ | (49,100 | ) | $ | (924,300 | ) | ||||||||
Long-term assets | 3,375,500 | 6,787,000 | Long-term liabilities | (526,600 | ) | (831,500 | ) | |||||||||||||
Total derivatives |
$ | 7,483,500 | $ | 17,384,700 | $ | (575,700 | ) | $ | (1,755,800 | ) | ||||||||||
30
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 7 DERIVATIVE INSTRUMENTS (Continued)
Effects of Derivative Instruments on Statements of Operations:
Gain | Gain (Loss) | |||||||||||||||||||
Recognized in OCI on Derivative | Reclassified from OCI into Income | |||||||||||||||||||
(Effective Portion) | Location of Gain/(Loss) | (Effective Portion) | ||||||||||||||||||
Derivatives in | Twelve Months Ended | Reclassified from Accumulated | Twelve Months Ended | |||||||||||||||||
Cash Flow | December 31, | December 31, | OCI into Income | December 31, | December 31, | |||||||||||||||
Hedging Relationship | 2009 | 2008 | (Effective Portion) | 2009 | 2008 | |||||||||||||||
Commodity contracts |
$ | 4,821,700 | $ | 7,364,400 | Natural gas and oil revenue | $ | 9,427,000 | $ | (694,800 | ) | ||||||||||
At any point in time, such contracts may include regulated New York Mercantile Exchange
(NYMEX) futures, options contracts, and non-regulated over-the-counter futures contracts with
qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may
be settled by the delivery of natural gas. Oil contracts are based on a West Texas Intermediate
(WTI) index. These contracts have qualified and been designated as cash flow hedges and recorded
at their fair values.
At December 31, 2009, the Partnership reflected a net hedge asset on our Balance Sheets of
$6,907,800, however unrealized losses of $3,453,900 recognized in income results in a net other
comprehensive gain of $3,453,900. The unrealized gain of $3,453,900 is comprised of $574,400 and
$2,879,500 from 2009 and 2008 impairments, respectively. Of the $3,453,900 net gain in accumulated
other comprehensive loss at December 31, 2009, if the fair values of the instruments remain at
current market values, we will reclassify $2,242,400 of net gains to our Statements of Operations
over the next twelve month period as these contracts expire, and $1,211,500 of net gains later
periods. Actual amounts that will be reclassified will vary as a result of future price changes.
Ineffective hedge gains or losses are recorded within the Statements of Operations while the hedge
contract is open and may increase or decrease until settlement of the contract. The Partnership
recognized no gains or losses during the years ended December 31, 2009 and 2008, respectively, for
hedge ineffectiveness or as a result of the discontinuance of cash flow hedges.
As of December 31, 2009, Atlas Energy had allocated to the Partnership the following natural
gas and oil volumes hedged:
Natural Gas Fixed Price Swaps
Production | Average | |||||||||||
Period Ending | Volumes | Fixed Price | Fair Value | |||||||||
December 31, | (MMbtu)(1) | (per MMbtu)(1) | Asset (2) | |||||||||
2010 |
2,341,500 | $ | 7.34 | $ | 3,591,600 | |||||||
2011 |
1,223,700 | 6.98 | 1,080,700 | |||||||||
2012 |
972,500 | 7.22 | 811,900 | |||||||||
2013 |
526,400 | 7.08 | 219,700 | |||||||||
$ | 5,703,900 | |||||||||||
31
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 7 DERIVATIVE INSTRUMENTS (Continued)
Natural Gas Costless Collars
Production | Average | |||||||||||||
Period Ending | Option | Volumes | Floor & Cap | Fair Value | ||||||||||
December 31, | Type | (MMbtu)(1) | (per MMbtu)(1) | Asset (2) | ||||||||||
2010 |
Puts purchased | 162,300 | $ | 7.84 | $ | 399,700 | ||||||||
2010 |
Calls sold | 162,300 | 9.01 | | ||||||||||
2011 |
Puts purchased | 713,500 | 6.45 | 459,100 | ||||||||||
2011 |
Calls sold | 713,500 | 7.63 | | ||||||||||
2012 |
Puts purchased | 368,500 | 6.51 | 166,100 | ||||||||||
2012 |
Calls sold | 368,500 | 7.71 | | ||||||||||
2013 |
Puts purchased | 342,200 | 6.58 | 97,000 | ||||||||||
2013 |
Calls sold | 342,200 | 7.79 | | ||||||||||
$ | 1,121,900 | |||||||||||||
Crude Oil Fixed Price Swaps
Production | Average | |||||||||||
Period Ending | Volumes | Fixed Price | Fair Value | |||||||||
December 31, | (Bbl)(1) | (per Bbl)(1) | Asset (3) | |||||||||
2010 |
3,200 | $ | 97.40 | $ | 50,900 | |||||||
2011 |
2,700 | 77.46 | 9,000 | |||||||||
2012 |
2,000 | 76.86 | 2,000 | |||||||||
2013 |
600 | 77.36 | 200 | |||||||||
$ | 62,100 | |||||||||||
Crude Oil Costless Collars
Production | Average | |||||||||||||
Period Ending | Option | Volumes | Floor & Cap | Fair Value | ||||||||||
December 31, | Type | (Bbl)(1) | (per Bbl)(1) | Asset (Liability)(3) | ||||||||||
2010 |
Puts purchased | 2,100 | $ | 85.00 | $ | 16,700 | ||||||||
2010 |
Calls sold | 2,100 | 112.92 | | ||||||||||
2011 |
Puts purchased | 1,700 | 67.22 | 3,000 | ||||||||||
2011 |
Calls sold | 1,700 | 89.44 | | ||||||||||
2012 |
Puts purchased | 1,300 | 65.51 | 300 | ||||||||||
2012 |
Calls sold | 1,300 | 91.45 | | ||||||||||
2013 |
Puts purchased | 300 | 65.36 | | ||||||||||
2013 |
Calls sold | 300 | 93.44 | (100 | ) | |||||||||
$ | 19,900 | |||||||||||||
Total Net Asset | $ | 6,907,800 | ||||||||||||
(1) | MMBTU represents million British Thermal Units. Bbl represents barrels. |
|
(2) | Fair value based on forward NYMEX natural gas prices. |
|
(3) | Fair value based on forward WTI crude oil prices. |
32
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 8 FAIR VALUE OF FINANCIAL INSTRUMENTS
The Partnership has established a hierarchy to measure its financial instruments at fair
value which requires it to maximize the use of observable inputs and minimize the use of
unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that
may be used to measure fair value.
Level 1 | Unadjusted quoted prices in active markets for identical assets and
liabilities that the reporting entity has the ability to access at
the measurement date. |
Level 2 | Inputs other than quoted prices included within Level 1 that are observable
for the asset and liability or can be corroborated with observable market data for
substantially the entire contractual term of the asset or
liability. |
Level 3 | Unobservable inputs that reflect the entities own assumptions about the
assumptions that market participants would use in the pricing of the asset or liability
and are consequently not based on market activity, but rather through particular
valuation techniques. |
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The Partnership uses a fair value methodology to value the assets and liabilities for its
outstanding derivative contracts (see Note 7). The Partnerships derivative contracts are valued
based on observable market data related to the change in price of the underlying commodity and are
therefore defined as Level 2 fair value measurements. Assets and Liabilities measured at fair
value at December 31, 2009 and 2008 were as follows.
December 31, 2009 | December 31, 2008 | |||||||||||||||
Level 2 | Total | Level 2 | Total | |||||||||||||
Commodity-based derivatives |
$ | 6,907,800 | $ | 6,907,800 | $ | 15,628,900 | $ | 15,628,900 | ||||||||
Total |
$ | 6,907,800 | $ | 6,907,800 | $ | 15,628,900 | $ | 15,628,900 | ||||||||
33
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 8 FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
The Partnership estimates the fair value of asset retirement obligations, using Level 3
inputs based on discounted cash flow projections using numerous estimates, assumptions and
judgments regarding such factors at the date of establishment of an asset retirement obligation
such as: amount and timing of settlements; the risk-free rate of the Partnership; and estimated
inflation rates (see Note 9).
The Partnerships long-lived assets are reviewed for impairment at least annually or whenever
events or changes in circumstances indicate that the carrying amount of an asset may not be
recoverable. If the carrying value exceeds such undiscounted cash flows, an impairment loss is
recognized for the difference between the estimated fair market value and the carrying value of
the assets. The fair market value using Level 3 inputs is determined as the present value of
future net revenues from the production of proved reserves discounted using an annual discount
rate of 12% in 2009 and 2008 (see Note 2).
NOTE 9 ASSET RETIREMENT OBLIGATION
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil
and gas wells. The associated asset retirement costs are capitalized as part of oil and gas
properties. The Partnership also considers the estimated salvage value in the calculation of
depletion.
The estimated liability is based on the MGPs historical experience in plugging and abandoning
wells, estimated remaining lives of those wells based on reserve estimates, external estimates as
to the cost to plug and abandon the wells in the future and federal and state regulatory
requirements. The liability is discounted using an assumed risk free interest rate. Revisions to
the liability could occur due to changes in estimates of plugging and abandonment costs or
remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment
requirements. The Partnership has no assets legally restricted for purposes of settling asset
retirement obligations.
A reconciliation of the Partnerships liability for plugging and abandonment costs for the
years indicated are:
December 31, | ||||||||
2009 | 2008 | |||||||
Asset retirement obligation at beginning of period |
$ | 3,298,000 | $ | | ||||
Liabilities incurred from drilling wells |
| 3,130,500 | ||||||
Revision in estimates |
1,040,100 | | ||||||
Accretion expense |
197,900 | 167,500 | ||||||
Asset retirement obligation at end of period |
$ | 4,536,000 | $ | 3,298,000 | ||||
34
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 10 NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
(1) | Capitalized Costs Related to Oil and Gas Producing Activities |
The following table presents the capitalized costs related to natural gas and oil producing
activities at the period indicated:
At December 31, | ||||||||
2009 | 2008 | |||||||
Mineral interest in proved properties |
$ | 5,366,700 | $ | 5,366,700 | ||||
Wells and related equipment |
301,921,800 | 282,115,600 | ||||||
Accumulated depletion |
(167,601,500 | ) | (144,965,200 | ) | ||||
Net capitalized cost |
$ | 139,687,000 | $ | 142,517,100 | ||||
(2) | Oil and Gas Reserve Information |
In accordance with the modernization of oil and gas accounting (see Note 2), the Partnership
changed its calculation of proved reserves. Under the current accounting literature, the proved
reserves quantities and future net cash flows are estimated using a 12-month average pricing at
December 31, 2009 based on the prices on the first day of each month. Using this calculation
resulted in the use of lower prices at December 31, 2009 than would have resulted using year-end
prices as required by the previous rules.
The preparation of the Companys natural gas and oil reserve estimates were completed in
accordance with its prescribed internal control procedures, which include verification of input
data delivered to its third-party reserve specialist, as well as a multi-functional management
review. For the year ended December 31, 2009, the Company retained Wright & Company, independent,
third-party reserves engineers, to prepare a report of proved reserves. The reserves report
included a detailed review of our properties. Wright & Companys evaluation was based on more than
35 years of experience in the estimation of and evaluation of petroleum reserves, specified
economic parameters, operating conditions, and government regulations applicable as of December 31,
2009. The Wright & Company report was prepared in accordance with generally accepted petroleum
engineering and evaluation principles.
The reserve disclosures that follow reflect estimates of proved reserves consisting of proved
developed, net to the Partnerships interests, of natural gas, crude oil, condensate and NGLs owned
at year end and changes in proved reserves during the previous two years. Proved developed reserves
are those proved reserves, which can be expected to be recovered from existing wells with existing
equipment and operating methods.
There are numerous uncertainties inherent in estimating quantities of proven reserves and in
projecting future net revenues and the timing of development expenditures. The reserve data
presented represents estimates only and should not be construed as being exact. In addition, the
standardized measures of discounted future net cash flows may not represent the fair market value
of the Partnerships oil and gas reserves or the present value of future cash flows of equivalent
reserves, due to anticipated future changes in oil and gas prices and in production and development
costs and other factors for effects have not been proved.
35
ATLAS RESOURCES PUBLIC 17-2008 (B) L.P.
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTES TO FINANCIAL STATEMENTS (Continued)
DECEMBER 31, 2009 AND 2008
NOTE 10 NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (Continued)
Natural Gas | Oil | |||||||
(Mcf) | (Bbls) | |||||||
Proved developed reserves: |
||||||||
Beginning of period |
| | ||||||
Proved developed reserves |
51,231,100 | 98,500 | ||||||
Production |
(2,470,600 | ) | (9,100 | ) | ||||
Balance December 31, 2008 |
48,760,500 | 89,400 | ||||||
Proved developed reserves: |
||||||||
Production |
(4,866,200 | ) | (26,000 | ) | ||||
Revision to previous estimates |
(11,095,300 | ) | 22,300 | |||||
Balance December 31, 2009 |
32,799,000 | 85,700 | ||||||
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
We maintain disclosure controls and procedures that are designed to ensure that information
required to be disclosed in our Securities Exchange Act of 1934 reports is recorded, processed,
summarized and reported within the time periods specified in the SECs rules and forms, and that
such information is accumulated and communicated to our management, including our Chairman of the
Board of Directors, Chief Executive Officer, President and Chief Financial Officer, as appropriate,
to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure
controls and procedures, our management recognized that any controls and procedures, no matter how
well designed and operated, can provide only reasonable assurance of achieving the desired control
objectives, and our management necessarily was required to apply its judgment in evaluating the
cost-benefit relationship of possible controls and procedures.
Under the supervision of our Chairman of the Board of Directors, Chief Executive Officer,
President and Chief Financial Officer, we have carried out an evaluation of the effectiveness of
our disclosure controls and procedures as of the end of the period covered by this report. Based
upon that evaluation, our Chairman of the Board of Directors, Chief Executive Officer, President
and Chief Financial Officer, concluded that, as of December 31, 2009, our disclosure controls and
procedures were effective at the reasonable assurance level.
36
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 Rules 13a-15(f). Under the supervision
and with the participation of management, including our Chairman of the Board of Directors, Chief
Executive Officer, President and Chief Financial Officer, we conducted an evaluation of the
effectiveness of internal control over financial reporting based upon criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission in Internal Control Integrated
Framework (COSO framework).
An effective internal control system, no matter how well designed, has inherent limitations,
including the possibility of human error and circumvention or overriding of controls and therefore
can provide only reasonable assurance with respect to reliable financial reporting. Furthermore,
effectiveness of an internal control system in future periods cannot be guaranteed because the
design of any system of internal controls is based in part upon assumptions about the likelihood of
future events. There can be no assurance that any control design will succeed in achieving its
stated goals under all potential future conditions. Over time certain controls may become
inadequate because of changes in business conditions, or the degree of compliance with policies and
procedures may deteriorate. As such, misstatements due to error or fraud may occur and not be
detected.
Based on our evaluation under the COSO framework, management concluded that our internal
control over financial reporting as of December 31, 2009 was effective.
This annual report does not include an attestation report by the Companys registered public
accounting firm regarding internal control over financial reporting. Managements report was not
subject to attestation by the Companys registered public accounting firm pursuant to temporary
rules of the Securities and Exchange Commission that permit the Company to provide only
managements report in this annual report.
ITEM 9B. | OTHER INFORMATION |
None.
PART III
ITEM 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT |
Atlas Energy is headquartered at Westpointe Corporate Center One, 1550 Coraopolis Heights
Road, 2nd Floor, Moon Township, Pennsylvania 15108, which is also our MGPs primary
office.
Executive Officers and Directors. The executive officers and directors of our MGP will serve until
their successors are elected. The executive officers and directors of our MGP are as follows:
NAME | AGE | POSITION OR OFFICE | ||||
Freddie M. Kotek
|
54 | Chairman of the Board of Directors, Chief Executive Officer and President | ||||
Frank P. Carolas
|
50 | Executive Vice President Land and Geology and a Director | ||||
Jeffrey C. Simmons
|
51 | Executive Vice President Operations and a Director | ||||
Jack L. Hollander
|
53 | Senior Vice President Direct Participation Programs | ||||
Sean P. McGrath
|
38 | Chief Accounting Officer | ||||
Matthew A. Jones
|
48 | Chief Financial Officer |
37
With respect to the biographical information set forth below:
| the approximate amount of an individuals professional time devoted to the business and
affairs of our MGP and Atlas America have been aggregated because there is no reasonable
method for them to distinguish their activities between the two companies; and |
| for those individuals who also hold senior positions with other affiliates of our MGP,
if it is stated that they devote approximately 100% of their professional time to our MGP
and Atlas America, it is because either the other affiliates are not currently active in
drilling new wells, such as Viking Resources or Resource Energy, and the individuals are
not required to devote a material amount of their professional time to the affiliates, or
there is no reasonable method to distinguish their activities between our MGP and Atlas
America as compared with the other affiliates of our MGP, such as Viking Resources or
Resource Energy. |
Freddie M. Kotek has been an Executive Vice President since February 2004 and served as a director
from September 2001 until February 2004. Mr. Kotek has been Chairman of Atlas Resources, LLC since
September 2001 and has served as an Executive Vice President since October 2009. He has also served
as Chief Executive Officer and President of Atlas Resources since January 2002. Mr. Kotek was our
Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President
of Resource America from 1995 until May 2004 and President of Resource Leasing, Inc. (a
wholly-owned subsidiary of Resource America) from 1995 until May 2004. Kotek will devote
approximately 95% of his professional time to the business and affairs of the MGP and Atlas
America, Atlas Energy Resources, LLC and Atlas Energy Management, Inc., and the remainder of his
professional time to the business and affairs of the MGPs other affiliates.
Frank P. Carolas. Executive Vice President-Land and Geology and a Director since January 2001. Mr.
Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a
Director of Atlas America from January 2002 until February 2004. Mr. Carolas has been a Senior Vice
President of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of Resource
America from April 2001 until May 2004 when he resigned from Resource America. Mr. Carolas served
as Vice President of Land and Geology for the MGP from July 1999 until December 2000 and for Atlas
America from 1998 until December 2000. Before that Mr. Carolas served as Vice President of Atlas
Energy Group, Inc. from 1997 until 1998, which was the former parent company of the MGP. Mr.
Carolas is a certified petroleum geologist and has been with the MGP and its affiliates since 1981.
He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and
is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes
approximately 100% of his professional time to the business and affairs of the MGP, Atlas America,
Atlas Energy Resources, LLC and Atlas Energy Management, Inc.
Jeffrey C. Simmons. Executive Vice President-Operations and a Director since January 2001. Mr.
Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director
of Atlas America from January 2002 until February 2004. Mr. Simmons has been a Senior Vice
President of Atlas Energy Management, Inc., since 2006. Mr. Simmons was a Vice President of
Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons
served as Vice President of Operations for the MGP from July 1999 until December 2000 and for Atlas
America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior
petroleum engineer and has served in various executive positions with its energy subsidiaries since
then. Mr. Simmons received his Bachelor of Science degree with honors from Marietta College in 1981
and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons
devotes approximately 90% of his professional time to the business and affairs of the MGP, Atlas
America, and the remainder of his professional time to the business and affairs of the MGPs other
affiliates, primarily Viking Resources and Resource Energy, Atlas Energy Resources, LLC and Atlas
Energy Management, Inc.
38
Jack L. Hollander. Senior Vice President Direct Participation Programs since January 2002 and
before that he served as Vice President Direct Participation Programs from January 2001 until
December 2001. Mr. Hollander also serves as Senior Vice President Direct Participation Programs
of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander &
Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001,
and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services
company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University
of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law
degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander
is a member of the New York State bar, and the Chairman of the Investment Program Association which
is an industry association, as of March 2005. Mr. Hollander devotes approximately 100% of his
professional time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources,
LLC and Atlas Energy Management, Inc.
Sean P. McGrath has been our Chief Accounting Officer and the Chief Accounting Officer of Atlas
Energy Resources since December 2008. Mr. McGrath served as the Chief Accounting Officer of Atlas
Pipeline Holdings GP from January 2006 until November 2009 and as the Chief Accounting Officer of
Atlas Pipeline GP from May 2005 until November 2009. Mr. McGrath was the Controller of Sunoco
Logistics Partners L.P., a publicly-traded partnership that transports, terminals and stores
refined products and crude oil, from 2002 to 2005. From 1998 to 2002, Mr. McGrath was Assistant
Controller of Asplundh Tree Expert Co., a utility services and vegetation management company.
Mr. McGrath is a Certified Public Accountant. Mr. McGrath will devote approximately 70% of his
professional time to the business and affairs of the managing general partner and Atlas America,
and the remainder of his professional time to the business and affairs of the managing general
partners other affiliates.
Matthew A. Jones has been our Chief Financial Officer since March 2005 and an Executive Vice
President since October 2009. Mr. Jones has been the Chief Financial Officer of Atlas Energy
Resources and Atlas Energy Management since their formation. Mr. Jones served as the Chief
Financial Officer of Atlas Pipeline Holdings GP from January 2006 until September 2009 as the Chief
Financial Officer of Atlas Pipeline GP from March 2005 to September 2009. From 1996 to 2005,
Mr. Jones worked in the Investment Banking Group at Friedman Billings Ramsey, concluding as
Managing Director. Mr. Jones worked in Friedman Billings Ramseys Energy Investment Banking Group
from 1999 to 2005, and in Friedman Billings Ramseys Specialty Finance and Real Estate Group from
1996 to 1999. Mr. Jones has served as a director of Atlas Pipeline Holdings GP since February 2006.
Mr. Jones is a Chartered Financial Analyst. Mr. Jones devotes approximately 55% of his professional
time to the business and affairs of the MGP, Atlas America, Atlas Energy Resources, LLC and Atlas
Energy Management, Inc. and the remainder of his professional time to the business and affairs of
the MGPs other affiliates.
Audit Committee Financial Expert. The Board of Directors of our MGP acts as the audit committee.
The Board of Directors has determined that Freddie M. Kotek, Chairman and President of the MGP,
meets the requirement of an audit committee financial expert. He is not independent.
Remuneration of Officers and Directors. No officer or director of the MGP will receive any direct
remuneration or other compensation from the Partnership. These persons will receive compensation
solely from affiliated companies of the MGP.
Code of Business Conduct and Ethics. Because the Partnership does not directly employ any persons,
the MGP has determined that the partnership will rely on a Code of business Conduct and Ethics
adopted by Atlas Energy, Inc. and/or Atlas Energy Resources, LLC that applies to the principal
executive officer, principal financial officer and principal accounting officer of the MGP, as well
as to persons performing services for the MGP generally. You may obtain a copy of this Code of
Business Conduct and Ethics by a request to the MGP at Atlas Resources, LLC, Westpointe Corporate
Center One, 1550 Coraopolis Heights Road, 2nd Floor, Moon Township, Pennsylvania 15108.
ITEM 11. | EXECUTIVE COMPENSATION |
We have no employees and rely on the employees of our MGP and its affiliates for all services.
No officer or director of our MGP will receive any direct remuneration or other compensation from
us. Those persons will receive compensation solely from affiliated companies of our MGP. See Item
13 Certain Relationships and Related Transactions for a discussion of compensation paid by us to
our MGP.
39
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT |
As of December 31, 2009, we had 23,644.10 units outstanding. Jack Hollander, an officer of our
MGP owns 1.50 units, which equals a partnership interest of .006%. Although, subject to certain
conditions, investor partners may present their units to us beginning in 2013 for purchase, the MGP
is not obligated by the Partnership agreement to purchase more than 5% of our total outstanding
units in any calendar year.
Organizational and Security Ownership of Beneficial Owners. Atlas Energy, Inc. owns
approximately 100% of the limited liability company interest of Atlas Energy Resources, LLC which
owns 100% of the limited liability company interests of Atlas Energy Operating Company, LLC, which
owns 100% of the limited liability company interests of AIC, LLC, which owns 100% of the limited
liability company interest of the MGP. The officers and directors of Atlas America and Atlas Energy
Resources, LLC are set forth below. The directors of AIC, LLC are Jonathan Z. Cohen, and Jeffrey
Simmons.
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS |
Oil and Gas Revenues. Our MGP is allocated 35.17% of our oil and gas revenues in return for
its payment and/or contribution of services towards our syndication and offering costs equal to
10.35% of our subscriptions, its payment of 82.02% of the tangible costs of drilling and completing
our wells and its contributions to us of all of our oil and gas leases for a total capital
contribution of $91,524,500. During the years ended December 31, 2009 and 2008, our MGP received
$7,965,200 and $6,352,700, respectively, for our net production revenues.
Leases. Following the final closing date, for the offering of our units to potential
investors, which was December 31, 2008 our MGP contributed oil and gas leases to us covering 506
undeveloped prospects for the wells we drilled and received a credit to its capital account in the
amount of $5,366,700.
Administrative Costs. Our MGP and its affiliates receive an unaccountable, fixed fee
reimbursement for their administrative costs of $75 per well per month, which is proportionately
reduced if we acquire less than 100% of the working interest in a well. During the years ended
December 31, 2009 and 2008, our MGP received $364,800 and $95,500, respectively for its
administrative costs.
Direct Costs. Our MGP and its affiliates are reimbursed for all direct costs expended on our
behalf. During the year ended December 31, 2009 and 2008 our MGP received $5,216,000 and
$1,175,500, respectively, for direct costs.
Well Charges. Our MGP, as operator, is reimbursed at actual cost for all direct expenses
incurred on our behalf and receives well supervision fees for operating and maintaining the wells
during producing operations in the amount of $377 per well per month subject to an annual
adjustment for inflation. The well supervision fees are proportionately reduced to the extent we
acquire less than 100% of the working interest in a well. For the years ended December 31, 2009 and
2008, our MGP received $1,833,500 and $480,100, respectively, for well supervision fees.
Transportation Fees. We pay gathering fees to our MGP at a competitive rate for each mcf of
our natural gas transported. Transportation rate is generally 13% of the natural gas sales price.
For the years ended December 31, 2009 and 2008, $4,851,700 and $2,956,700 was paid to our MGP for
gathering fees. In turn, our MGP paid 100% of this amount to Atlas America, for the use of its
gathering system in transporting a majority of our natural gas production.
40
ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
Audit Fees. The aggregate fees recognized by the Partnership from our independent auditors,
Grant Thornton LLP, for professional services rendered for the audit of our annual financial
statements for the years ended December 31, 2009 and 2008 were $31,600 and $14,600, respectively.
Procedures for Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of
Independent Auditor. Pursuant to its charter, the Audit Committee of Atlas Energy, Inc. is
responsible for reviewing and approving, in advance, any audit and any permissible non-audit
engagement or relationship between us and our independent auditors. We do not have a separate audit
committee.
PART IV
ITEM 15. | EXHIBITS |
EXHIBIT INDEX
Description | Location | |||||
4(a) | Certificate of Limited Partnership for Atlas
Resources Public 17-2008 (B) L.P.
|
Previously filed in our Form S-1/A on October 10, 2007 | ||||
4(b) | Amended and Restated Certificate and Agreement of Limited
Partnership for Atlas Resources Public 17-2008 (B) L.P. (1)
|
Previously filed in our Form S-1/A on October 10, 2007 | ||||
4(c) | Drilling and Operating Agreement for Atlas
Resources Public 17-2008 (B) L.P. (1)
|
Previously filed in our Form S-1/A on October 10, 2007 | ||||
23.1 | Consent of Wright and Company, Inc. |
|||||
31.1 | Rule 13a-14(a)/15(d) 14 (a) Certification |
|||||
31.2 | Rule 13a-14(a)/15(d) 14 (a) Certification. |
|||||
32.1 | Section 1350 Certification. |
|||||
32.2 | Section 1350 Certification. |
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99.1 | Summary Reserve Report |
(1) | Filed on June 27, 2007 in the Form S-1 Registration Statement dated June 27, 2007, File No. 333-144070 |
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SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report
to be signed on its
behalf by the undersigned, thereunto duly authorized.
Atlas Resources Public 17-2008 (B) L.P.
Date: March 30, 2010 | Atlas Resources, LLC, Managing General Partner |
|||
By: | /s/ Freddie M. Kotek | |||
Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President |
In accordance with the Exchange Act, this report has been signed by the following persons on
behalf of the
registrant and in the capacities and on the dates indicated.
Date: March 30, 2010 | By: | /s/ Freddie M. Kotek | ||
Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President |
||||
Date: March 30, 2010 | By: | /s/ Frank P. Carolas | ||
Frank P. Carolas, Executive Vice President Land and Geology | ||||
Date: March 30, 2010 | By: | /s/ Jeffrey C. Simmons | ||
Jeffrey C. Simmons, Executive Vice President Operations | ||||
Date: March 30, 2010 | By: | /s/ Sean P. McGrath | ||
Sean P. McGrath, Chief Accounting Officer | ||||
Date: March 30, 2010 | By: | /s/ Matthew A. Jones | ||
Matthew A. Jones, Chief Financial Officer |
Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the
Exchange Act by Non-reporting Issuers
Exchange Act by Non-reporting Issuers
An annual report will be furnished to security holders subsequent to the filing of this report.
42