Attached files
file | filename |
---|---|
EXCEL - IDEA: XBRL DOCUMENT - Atlas Resources Series 28-2010 L.P. | Financial_Report.xls |
EX-31.2 - EXHIBIT 31.2 - Atlas Resources Series 28-2010 L.P. | c21062exv31w2.htm |
EX-32.1 - EXHIBIT 32.1 - Atlas Resources Series 28-2010 L.P. | c21062exv32w1.htm |
EX-31.1 - EXHIBIT 31.1 - Atlas Resources Series 28-2010 L.P. | c21062exv31w1.htm |
EX-32.2 - EXHIBIT 32.2 - Atlas Resources Series 28-2010 L.P. | c21062exv32w2.htm |
Table of Contents
United States
Securities and Exchange Commission
Securities and Exchange Commission
Washington, D.C. 20549
Form 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
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 000-54378
ATLAS RESOURCES SERIES 28-2010 L. P.
(Name of small business issuer in its charter)
Delaware | 27-2101952 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
Westpointe Corporate Center One | ||
1550 Coraopolis Heights Rd. 2nd Floor | ||
Moon Township, PA | 15108 | |
(Address of principal executive offices) | (zip code) |
Issuers telephone number, including area code: (412) 262-2830
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting
company. See the definitions of large accelerated filer, accelerated filer, non accelerated 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 Exchange Act). Yes o No þ
ATLAS RESOURCES SERIES 28-2010 L. P.
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO QUARTERLY REPORT
(A DELAWARE LIMITED PARTNERSHIP)
INDEX TO QUARTERLY REPORT
ON FORM 10-Q
PAGE | ||||||||
3 | ||||||||
4 | ||||||||
5 | ||||||||
6 | ||||||||
7-15 | ||||||||
15-18 | ||||||||
18 | ||||||||
18 | ||||||||
19 | ||||||||
20 | ||||||||
CERTIFICATIONS |
||||||||
Exhibit 31.1 | ||||||||
Exhibit 31.2 | ||||||||
Exhibit 32.1 | ||||||||
Exhibit 32.2 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
EX-101 DEFINITION LINKBASE DOCUMENT |
2
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
BALANCE SHEET
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
(Unaudited) | ||||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 450,600 | $ | | ||||
Accounts receivable affiliate |
3,570,800 | 1,153,700 | ||||||
Short-term hedge receivable due from affiliate |
| 1,325,500 | ||||||
Total current assets |
4,021,400 | 2,479,200 | ||||||
Oil and gas properties, net |
131,860,600 | 100,874,300 | ||||||
Construction in progress |
36,392,400 | 65,071,800 | ||||||
Long-term hedge receivable due from affiliate |
| 1,665,800 | ||||||
Long-term receivable due from affiliate |
1,071,500 | | ||||||
$ | 173,345,900 | $ | 170,091,100 | |||||
LIABILITIES AND PARTNERS CAPITAL |
||||||||
Current liabilities: |
||||||||
Accrued liabilities |
$ | 31,200 | $ | 34,900 | ||||
Short-term hedge liability due to affiliate |
| 4,300 | ||||||
Total current liabilities |
31,200 | 39,200 | ||||||
Asset retirement obligation |
1,686,600 | 1,407,800 | ||||||
Long-term hedge liability due to affiliate |
| 162,300 | ||||||
Partners capital: |
||||||||
Managing general partner |
22,172,300 | 17,468,800 | ||||||
Limited partners (7,500 units) |
147,352,900 | 148,188,300 | ||||||
Accumulated other comprehensive income |
2,102,900 | 2,824,700 | ||||||
Total partners capital |
171,628,100 | 168,481,800 | ||||||
$ | 173,345,900 | $ | 170,091,100 | |||||
See accompanying notes to financial statements.
3
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
STATEMENT OF OPERATIONS
June 30, 2011
(Unaudited)
Period Ended | Period Ended | |||||||||||||||
Three Months | April 1, 2010 | Six Months | April 1, 2010 | |||||||||||||
Ended | Through | Ended | Through | |||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
REVENUES |
||||||||||||||||
Natural gas |
$ | 3,185,400 | $ | 13,000 | $ | 6,057,600 | $ | 13,000 | ||||||||
Total revenues |
3,185,400 | 13,000 | 6,057,600 | 13,000 | ||||||||||||
COSTS AND EXPENSES |
||||||||||||||||
Production |
1,328,300 | 2,700 | 2,362,500 | 2,700 | ||||||||||||
Depletion |
1,334,700 | 6,800 | 2,739,600 | 6,800 | ||||||||||||
Accretion of asset retirement obligation |
24,500 | | 47,400 | | ||||||||||||
General and administrative |
18,500 | 100 | 42,500 | 100 | ||||||||||||
Total costs and expenses |
2,706,000 | 9,600 | 5,192,000 | 9,600 | ||||||||||||
Net income |
$ | 479,400 | $ | 3,400 | $ | 865,600 | $ | 3,400 | ||||||||
Allocation of net income: |
||||||||||||||||
Managing general partner |
$ | 270,100 | $ | 500 | $ | 500,100 | $ | 500 | ||||||||
Limited partners |
$ | 209,300 | $ | 2,900 | $ | 365,500 | $ | 2,900 | ||||||||
Net income per limited partnership unit |
$ | 28 | $ | 2 | $ | 49 | $ | 2 | ||||||||
See accompanying notes to financial statements.
4
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
STATEMENT OF CHANGES IN PARTNERS CAPITAL
June 30, 2011
(Unaudited)
Accumulated | ||||||||||||||||
Managing | Other | |||||||||||||||
General | Limited | Comprehensive | ||||||||||||||
Partner | Partners | Income (Loss) | Total | |||||||||||||
Balance at January 1, 2011 |
$ | 17,468,800 | $ | 148,188,300 | $ | 2,824,700 | $ | 168,481,800 | ||||||||
Partners capital contributions: |
||||||||||||||||
Syndication and offering costs |
102,000 | | | 102,000 | ||||||||||||
Tangible equipment/leasehold costs |
4,815,100 | | | 4,815,100 | ||||||||||||
Total contributions |
4,917,100 | | | 4,917,100 | ||||||||||||
Syndication and offerings, immediately
charged to capital |
(102,000 | ) | | | (102,000 | ) | ||||||||||
4,815,100 | | | 4,815,100 | |||||||||||||
Participation in revenues and expenses: |
||||||||||||||||
Net production revenues |
1,115,400 | 2,579,700 | | 3,695,100 | ||||||||||||
Depletion |
(584,900 | ) | (2,154,700 | ) | | (2,739,600 | ) | |||||||||
Accretion of asset retirement obligation |
(16,000 | ) | (31,400 | ) | | (47,400 | ) | |||||||||
General and administrative |
(14,400 | ) | (28,100 | ) | | (42,500 | ) | |||||||||
Net income |
500,100 | 365,500 | | 865,600 | ||||||||||||
Other comprehensive loss |
| | (721,800 | ) | (721,800 | ) | ||||||||||
Distributions to partners |
(611,700 | ) | (1,200,900 | ) | | (1,812,600 | ) | |||||||||
Balance at June 30, 2011 |
$ | 22,172,300 | $ | 147,352,900 | $ | 2,102,900 | $ | 171,628,100 | ||||||||
See accompanying notes to financial statements.
5
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
STATEMENT OF CASH FLOWS
(Unaudited)
Period Ended | ||||||||
Six Months | April 1, 2010 | |||||||
Ended | Through | |||||||
June 30, | June 30, | |||||||
2011 | 2010 | |||||||
Cash flows from operating activities: |
||||||||
Net income |
$ | 865,600 | $ | 3,400 | ||||
Adjustments to reconcile net income to net cash
provided by operating activities: |
||||||||
Depletion |
2,739,600 | 6,800 | ||||||
Accretion of asset retirement obligation |
47,400 | | ||||||
Increase in accounts receivable-affiliate |
(1,385,700 | ) | (10,200 | ) | ||||
Decrease in accrued liabilities |
(3,700 | ) | | |||||
Net cash provided by operating activities |
2,263,200 | | ||||||
Cash flows from investing activities: |
||||||||
Oil and gas well drilling contract paid to MGP |
| (29,800,000 | ) | |||||
Net cash used in investing activities |
| (29,800,000 | ) | |||||
Cash flows from financing activities: |
||||||||
Initial capital contribution by MGP |
| 100 | ||||||
Partners capital contribution |
| 33,080,700 | ||||||
Distribution to partners |
(1,812,600 | ) | | |||||
Net cash (used in) provided by financing activities |
(1,812,600 | ) | 33,080,800 | |||||
Net income in cash and cash equivalents |
450,600 | 3,280,800 | ||||||
Cash and cash equivalents at beginning of period |
| | ||||||
Cash and cash equivalents at end of period |
$ | 450,600 | $ | 3,280,800 | ||||
Supplemental Schedule of non-cash financing activities: |
||||||||
Assets contributed by managing general partner: |
||||||||
Tangible drilling costs |
3,660,700 | 2,557,300 | ||||||
Lease costs |
1,154,400 | 1,160,500 | ||||||
Syndication and offering costs |
102,000 | 5,579,300 | ||||||
$ | 4,917,100 | $ | 9,297,100 | |||||
Asset retirement obligation |
$ | 231,400 | | |||||
See accompanying notes to financial statements.
6
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS
June 30, 2011
June 30, 2011
(Unaudited)
NOTE 1 DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Atlas Resources Series 28-2010 L.P. (the Partnership) is a Delaware limited partnership and
formed on April, 1, 2010 with Atlas Resources, LLC serving as its Managing General Partner and
operator (Atlas Resources or MGP). Atlas Resources is an indirect subsidiary of Atlas Energy,
L.P., formerly Atlas Pipeline Holdings, L.P. (Atlas Energy) (NYSE: ATLS). On February 17, 2011,
Atlas Energy, a then-majority owned subsidiary of Atlas Energy, Inc. and parent of the general
partner of Atlas Pipeline Partners, L.P. (APL) (NYSE: APL), completed an acquisition of assets
from Atlas Energy, Inc., which included its investment partnership business; its oil and gas
exploration, development and production activities conducted in Tennessee, Indiana, and Colorado,
certain shallow wells and leases in New York and Ohio, and certain well interests in Pennsylvania
and Michigan; and its ownership and management of investments in Lightfoot Capital Partners, L.P.
and related entities.
Atlas Resources focus is on the development and/or production of natural gas and oil in the
Appalachian, Michigan, Illinois, and/or Colorado basin regions of the United States of America.
Atlas Resources is also a 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 Resource Services, Inc. provides Atlas Resources with the personnel necessary to
manage its assets and raise capital.
The accompanying financial statements, which are unaudited except that the balance sheet at
December 31, 2010 is derived from audited financial statements, are presented in accordance with
the requirements of Form 10-Q and accounting principles generally accepted in the United States of
America (U.S. GAAP) for interim reporting. They do not include all disclosures normally made in
financial statements contained in the Form 10. These interim financial statements should be read in
conjunction with the audited financial statements and notes thereto presented in the Partnerships
Annual Report on Form 10 for the year ended December 31, 2010. The results of operations for the
six months ended June 30, 2011 may not necessarily be indicative of the results of operations for
the year ended December 31, 2011.
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In managements opinion, all adjustments necessary for a fair presentation of the
Partnerships financial position, results of operations and cash flows for the periods disclosed
have been made. Management has considered for disclosure any material subsequent events through the
date the financial statements were issued.
In addition to matters discussed further in this note, the Partnerships significant
accounting policies are detailed in its audited financial statements and notes thereto in the
Partnerships annual report on Form 10 for the year ended December 31, 2010 filed with the
Securities and Exchange Commission (SEC).
Use of Estimates
Preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and the 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.
7
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Use of Estimates (Continued)
The natural gas industry principally conducts its business by processing actual transactions
as much as 60 days after the month of delivery. Consequently, the most recent two months financial
results were recorded using estimated volumes and contract market prices. Differences between
estimated and actual amounts are recorded in the following months financial results. Management
believes that the operating results presented represent actual results in all material respects
(see Revenue Recognition accounting policy for further description).
Accounts Receivable and Allowance for Possible Losses
In evaluating the need for an allowance for possible losses, the MGP performs ongoing credit
evaluations of the Partnerships customers and adjusts credit limits based upon payment history and
the customers current creditworthiness, as determined by review of the Partnerships customers
credit information. Credit is extended on an unsecured basis to many of its energy customers. At
June 30, 2011 and December 31, 2010, the MGPs credit evaluation indicated that the Partnership had
no need for an allowance for possible losses.
Oil and Gas Properties
Oil and gas properties are stated at cost. Maintenance and repairs are expensed as incurred.
Major renewals and improvements that extend the useful lives of property are capitalized. The
Partnership follows the successful efforts method of accounting for oil and gas producing
activities. Oil is converted to gas equivalent basis (Mcfe) at the rate of one barrel equals 6
Mcf.
The Partnerships depletion expense is determined on a field-by-field basis using the
units-of-production method. Depletion rates for lease, well and related equipment costs are 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. Upon the
sale or retirement of a complete field of a proved property, the Partnership eliminates the cost
from the property accounts and the resultant gain or loss is reclassified to the Partnerships
statements of operations. Upon the sale of an individual well, the Partnership credits the proceeds
to accumulated depreciation and depletion within its balance sheets. As a result of retirements,
the Partnership reclassified $384,200 for the six months ended June 30, 2011 from oil and gas
properties to accumulated depletion.
June 30, | December 31, | |||||||
2011 | 2010 | |||||||
Proved properties: |
||||||||
Leasehold interests |
$ | 5,847,100 | $ | 4,812,700 | ||||
Wells and related equipment |
129,213,600 | 96,906,300 | ||||||
135,060,700 | 101,719,000 | |||||||
Accumulated depletion |
(3,200,100 | ) | (844,700 | ) | ||||
Oil and gas properties, net |
$ | 131,860,600 | $ | 100,874,300 | ||||
8
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Impairment of Long-Lived Assets
The Partnership reviews its long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be recoverable. If it is
determined that an assets estimated future cash flows will not be sufficient to recover its
carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset
to its estimated fair value if such carrying amount exceeds the fair value.
The review of the Partnerships oil and gas properties is done on a field-by-field basis by
determining if the historical cost of proved properties, less the applicable accumulated depletion,
and abandonment 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. Expected future cash flow from the sale of production of reserves is calculated
based on estimated future prices. The Partnership estimates prices based upon current contracts in
place, adjusted for basis differentials and market related information including published futures
prices. The estimated future level of production is based on assumptions surrounding future prices
and costs, field decline rates, market demand and supply and the economic and regulatory climates.
If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for
the difference between the estimated fair market value (as determined by discounted future cash
flows) and the carrying value of the assets.
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. In addition, reserve estimates
for wells with limited or no production history are less reliable than those based on actual
production. Estimated reserves are often subject to future revisions, which could be substantial,
based on the availability of additional information which could cause the assumptions to be
modified. The Partnership cannot predict what reserve revisions may be required in future periods.
There was no impairment charge recognized during the three and six months ended June 30, 2011 and
for the year ended December 31, 2010.
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 10% 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
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.
9
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 2 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)
Revenue Recognition
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 Partnerships 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.
The Partnership accrues unbilled revenue due to timing differences between the delivery of
natural gas and crude oil and the receipt of a delivery statement. These revenues are recorded
based upon volumetric data from the Partnerships records and management estimates of the related
commodity sales and transportation fees which are, in turn, based upon applicable product prices
(see Use of Estimates accounting policy for further description). The Partnership had unbilled
revenues at June 30, 2011 and December 31, 2010 of $1,891,200 and $856,100, respectively, which are
included in accounts receivable affiliate within the Partnerships balance sheets.
Recently Adopted Accounting Standards
In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income. Update
2011-05 amends the FASB Accounting Standards Codification to provide an entity with the option to
present the total of comprehensive income, the components of net income, and the components of
other comprehensive income in either a single continuous statement of comprehensive income or in
two separate but consecutive statements. In both choices, an entity is required to present each
component of net income along with a total net income, each component of other comprehensive
income, and a total amount for comprehensive income. Update 2011-05 eliminates the option to
present the components of other comprehensive income as part of the statement of changes in
partners capital. These changes apply to both annual and interim financial statements. Update
2011-05 will be effective for public entities fiscal years, and interim periods within those
years, beginning after December 15, 2011. The Partnership will apply the requirements of Update
2011-05 upon its effective date of January 1, 2012, and it does not anticipate it having a material
impact on its financial position, results of operations or related disclosures.
NOTE 3 ASSET RETIREMENT OBLIGATION
The Partnership recognizes an estimated liability for the plugging and abandonment of its oil
and gas wells and related facilities. It also recognizes a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be made. The
associated asset retirement costs are capitalized as part of the carrying amount of the long-lived
asset. 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 credit-adjusted 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. Except for its oil and gas properties, the Partnership has determined
that there are no other material retirement obligations associated with tangible long-lived assets.
10
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 3 ASSET RETIREMENT OBLIGATION (Continued)
Period Ended | Period Ended | |||||||||||||||
Three Months | April 1, 2010 | Six Months | April 1, 2010 | |||||||||||||
Ended | Through | Ended | Through | |||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Asset retirement obligation at beginning of period |
$ | 1,662,100 | $ | | $ | 1,407,800 | $ | | ||||||||
Liabilities incurred from drilling wells |
| | 231,400 | | ||||||||||||
Accretion expense |
24,500 | | 47,400 | | ||||||||||||
Asset retirement obligation at end of period |
$ | 1,686,600 | $ | | $ | 1,686,600 | $ | | ||||||||
NOTE 4 DERIVATIVE INSTRUMENTS
The MGP, on behalf of the Partnership, used a number of different derivative instruments,
principally swaps and collars, in connection with its commodity price risk management activities.
The MGP entered into financial instruments to hedge the Partnerships forecasted natural gas and
crude oil 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 received 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.
Historically, the MGP has entered into natural gas and crude oil future option contracts and
collar contracts on behalf of the Partnership to achieve more predictable cash flows by hedging its
exposure to changes in natural gas and oil prices. At any point in time, such contracts may include
regulated New York Mercantile Exchange (NYMEX) futures and 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. Crude 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.
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 MGP 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 income and reclassifies the portion relating to commodity
derivatives to gas and oil production revenues for the Partnerships derivatives within 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.
11
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 4 DERIVATIVE INSTRUMENTS (Continued)
Prior to the acquisition on February 17, 2011 of the Transferred Business, Atlas Energy,
Inc. monetized its derivative instruments related to the Transferred Business. The monetized
proceeds relate to instruments that were originally put into place to hedge future natural gas and
oil production of the Transferred Business, including production generated through its Drilling
Partnerships. At June 30, 2011, the Partnership recorded a net receivable from the monetized
derivative instruments of $1,031,400 in accounts receivable-affiliate and $1,071,500 in long-term
receivable-affiliate with the corresponding net unrealized gains in accumulated other comprehensive
income on the Partnerships balance sheets, which will be allocated to natural gas and oil
production revenue generated over the period of the original instruments contracts. As a result of
the monetization and the early settlement of natural gas and oil derivative instruments, the
Partnership recorded a net deferred gain on its balance sheets in other comprehensive income of
$2,102,900 as of June 30, 2011. During the period, $390,000 of monetized proceeds were recorded by
the Partnership and allocated only to the limited partners. Of the $2,102,900 of net unrealized
gain in accumulated other comprehensive income, the Partnership will reclassify $1,031,400 of net
gains to the Partnerships statements of operations over the next twelve month period and the
remaining $1,071,500 in later periods.
The following table summarizes the fair value of the Partnerships derivative instruments as
of December 31, 2010, as well as the gain or loss recognized in the statement of operations for the
three and six months ended June 30, 2011.
Fair Value of Derivative Instruments:
Fair Value | ||||||
Balance Sheet | December 31, | |||||
Derivatives in Cash Flow Hedging Relationships | Location | 2010 | ||||
Commodity Contracts |
Current assets | $ | 1,325,500 | |||
Long-term assets | 1,665,800 | |||||
2,991,300 | ||||||
Current liabilities | (4,300 | ) | ||||
Long-term liabilities | (162,300 | ) | ||||
(166,600 | ) | |||||
Total | $ | 2,824,700 | ||||
Effects of derivative instruments on Statement of Operations:
Period Ended | Period Ended | |||||||||||||||||
Three Months | April 1, 2010 | Six Months | April 1, 2010 | |||||||||||||||
Ended | Through | Ended | Through | |||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||
Derivative in Cash Flow Hedging Relationships |
Gain Recognized in OCI on Derivatives | |||||||||||||||||
Commodity Contracts | $ | | $ | | $ | 113,900 | $ | | ||||||||||
Period Ended | Period Ended | |||||||||||||||||
Three Months | April 1, 2010 | Six Months | April 1, 2010 | |||||||||||||||
Ended | Through | Ended | Through | |||||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||||
Location of Gain Reclassified from Accumulated OCI into Income |
Gain Reclassified from OCI into Net Income | |||||||||||||||||
Gas and Oil Revenue | $ | 369,800 | $ | | $ | 659,800 | $ | | ||||||||||
12
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 5 COMPREHENSIVE INCOME
Comprehensive income includes net income and all other changes in the 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 of America, have not been
recognized in the calculation of net income. These changes, other than net income, are referred to
as other comprehensive income (loss) and for the Partnership includes changes in the fair value
of unsettled derivative contracts accounted for as cash flow hedges, and changes in the estimated
amount of future monetized proceeds to be received (See Note 4). The monetized proceeds included in
accounts receivable affiliate have been allocated to the Partnership based on estimated future
production in relation to all other Partnerships future production eligible to receive monetized
hedge proceeds. As actual production is realized, there may be a corresponding difference in the
Partnerships actual share of monetized hedge proceeds received, than what was previously
estimated. This component is shown as Difference in estimated monetized gains receivable. A
reconciliation of the Partnerships comprehensive income for the periods indicated is as follows:
Period Ended | Period Ended | |||||||||||||||
Three Months | April 1, 2010 | Six Months | April 1, 2010 | |||||||||||||
Ended | Through | Ended | Through | |||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Net income |
$ | 479,400 | $ | 3,400 | $ | 865,600 | $ | 3,400 | ||||||||
Other comprehensive income: |
||||||||||||||||
Unrealized holding gain (loss) on hedging contracts |
| | (113,900 | ) | | |||||||||||
Difference in estimated monetized gain receivable |
61,700 | | 51,900 | | ||||||||||||
Less: reclassification adjustment for gains
realized in net income |
(369,800 | ) | | (659,800 | ) | | ||||||||||
Total other comprehensive loss |
(308,100 | ) | | (721,800 | ) | | ||||||||||
Comprehensive income |
$ | 171,300 | $ | 3,400 | $ | 143,800 | $ | 3,400 | ||||||||
NOTE 6 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 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
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 used a fair value methodology to value the assets and liabilities for its
outstanding derivative contracts (see Note 4). The Partnerships commodity derivative contracts
were 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.
13
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 6 FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)
Assets and Liabilities Measured at Fair Value on a Non-Recurring 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:
amounts and timing of settlements; the credit-adjusted risk-free rate of the Partnership; and
estimated inflation rates (see Note 3).
NOTE 7 TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES
The Partnership has entered into the following significant transactions with the MGP and its
affiliates as provided under the Partnership Agreement:
| Drilling contracts to drill and complete wells for the Partnership are charged at
cost plus 18%. The cost of the wells includes reimbursement to the Partnerships MGP of
its general and administrative overhead cost. No amounts were paid by the Partnership
to its MGP during the six months ended June 30, 2011. The Partnership paid $29,800,000
to its MGP during the period ended June 30, 2010. |
| Monthly well supervision fees which are included in production expenses in the
Partnerships Statement of Operations are payable at $975 per well, per month for
Marcellus wells, $1,500 per well, per month for New Albany wells, $600 per well, per
month for horizontal Antrim Shale wells and for Colorado wells, a fee of $400 is charged
per well, per month for operating and maintaining the wells. Well supervision fees
incurred were $232,600 and $434,400 for the three and six months ended June 30, 2011,
respectively. Well supervision fees incurred were $2,600 for the period ended April 1,
2010 through June 30, 2010. |
| 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 were $17,500 and $31,100 for the three and six months
ended June 30, 2011, respectively. Administrative costs incurred were $100 for the
period ended April 1, 2010 through June 30, 2010. |
| Transportation fees, which are included in production expenses in the Partnerships
statement of operations, incurred were $167,300 and $277,400 for the three and six
months ended June 30, 2011, respectively. Transportation fees incurred for the period
ended April 1, 2010 through June 30, 2010, were negligible. |
| Assets contributed from the MGP which are disclosed on the Partnerships statement of
cash flows as a non-cash activity for the six months ended June 30, 2011 and period
ended April 1, 2010 through June 30, 2010 were $4,815,100 and $3,717,800, respectively. |
| The MGP received a credit to its capital account of $102,000 and $5,579,300,
respectively, for the six months ended June 30, 2011 and period ended April 1, 2010
through June 30, 2010 for fees, commissions and reimbursement costs to organize the
partnership. |
The MGP and its affiliates perform all administrative and management functions for the
Partnership including billing revenues and paying expenses. Accounts receivable-affiliate on the
Partnerships Balance Sheet represents the net production revenues due from the MGP.
14
Table of Contents
ATLAS RESOURCES SERIES 28-2010 L. P.
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTES TO FINANCIAL STATEMENTS (Continued)
June 30, 2011
(Unaudited)
NOTE 7 TRANSACTIONS WITH ATLAS RESOURCES, LLC AND ITS AFFILIATES (Continued)
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 the benefit of the limited partners
for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination
period, 10% of their net subscriptions in each of the next three 12-month subordination periods,
and 8% of their net subscriptions in the fifth 12-month subordination period determined on a
cumulative basis, in each of the first five years of Partnership operations, commencing when the
MGP determines natural gas or oil is being sold from at least 75% of the partnerships wells,
excluding any wells drilled that were non-productive and expiring 60 months from that date. The
Partnerships first distribution was March 2011.
ITEM 2. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (UNAUDITED) |
Forward-Looking Statements
When used in this Form 10-Q, the words believes, anticipates, expects and similar
expressions are intended to identify forward-looking statements. These risks and uncertainties
could cause actual results to differ materially from the results stated or implied in this
document. Readers are cautioned not to place undue reliance on these forward-looking statements,
which speak only as of the date hereof. We undertake no obligation to publicly release the results
of any revisions to forward-looking statements which we may make to reflect events or circumstances
after the date of this Form 10-Q or to reflect the occurrence of unanticipated events.
Managements Discussion and Analysis should be read in conjunction with our Financial
Statements and the Notes to our Financial Statements.
Overview
The following discussion provides information to assist in understanding our financial
condition and result of operations. Our operating cash flows are generated from our wells, which
produce primarily natural gas, but also some oil. Our produced natural gas and oil is then
delivered to market through affiliated or third-party gas gathering systems. 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 managing general partner, as operator, a monthly
well supervision fee, which 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 competitive charge for services performed directly by our
managing general partner or its affiliates. Also, beginning one year after each of our wells has
been placed into production our managing general partner, as operator, may retain $200 per month,
per well to cover the estimated future plugging and abandonment costs of the well. As of June 30,
2011, our managing general partner had not withheld any funds for this purpose. Our managing
general partner intends to produce our wells 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.
15
Table of Contents
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 managing
general partner is responsible for selling our natural gas production. During 2011 and 2010, 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.
We have drilled and currently operate wells located in Pennsylvania, Michigan, Indiana and
Colorado. We have no employees and rely on our MGP for management, which in turn, relies on its
parent company, Atlas Energy Holdings Operating Company, LLC for administrative services.
Results of Operations
The following table sets forth information relating to our production revenues, volumes, sales
prices, production costs, and depletion during the periods indicated:
Period Ended | Period Ended | |||||||||||||||
Three Months | April 1, 2010 | Six Months | April 1, 2010 | |||||||||||||
Ended | Through | Ended | Through | |||||||||||||
June 30, | June 30, | June 30, | June 30, | |||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Production revenues (in thousands): |
||||||||||||||||
Gas |
$ | 3,185 | $ | 13 | $ | 6,058 | $ | 13 | ||||||||
Oil |
| | | | ||||||||||||
Total |
$ | 3,185 | $ | 13 | $ | 6,058 | $ | 13 | ||||||||
Production volumes: |
||||||||||||||||
Gas (mcf/day) (1) |
7,145 | 49 | 6,814 | 49 | ||||||||||||
Oil (bbls/day) (1) |
| | | | ||||||||||||
Total (mcfe/day) (1) |
7,145 | 49 | 6,814 | 49 | ||||||||||||
Average sales price: |
||||||||||||||||
Gas (per mcf) (1) |
$ | 4.90 | $ | 5.68 | $ | 4.91 | $ | 5.68 | ||||||||
Oil (per bbl) (1) |
$ | | $ | | $ | | $ | | ||||||||
Average production costs: |
||||||||||||||||
As a percent of revenues |
42 | % | 21 | % | 39 | % | 21 | % | ||||||||
Per mcfe (1) |
$ | 2.04 | $ | 1.18 | $ | 1.92 | $ | 1.18 | ||||||||
Depletion per mcfe |
$ | 2.05 | $ | 2.95 | $ | 2.22 | $ | 2.95 |
(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. |
16
Table of Contents
Natural Gas Revenues. Our natural gas revenues were $3,185,400 and $6,057,600, for the
three and six months ended June 30, 2011, respectively. Our production revenues for the period
ended April 1, 2010 through June 30, 2010 was $13,000. Our production volumes were 7,145 mcf and
6,814 mcf per day for the three and six months ended June 30, 2011, respectively. Our production
volumes were 49 mcf per day for the period ended April 1, 2010 through June 30, 2010. We expect
that our natural gas revenues will increase over the next year, as more of our wells are put online
and are producing larger volumes of natural gas.
Costs and Expenses. Production expenses were $1,328,300 and $2,362,500 for the three and six
months ended June 30, 2011, respectively. Production expenses were $2,700 for the period ended
April 1, 2010 through June 30, 2010.
Depletion of oil and gas properties as a percentage of oil and gas revenues was 42% and 45%
for the three and six months ended June 30, 2011, respectively. Depletion of oil and gas properties
as a percentage of oil and gas revenues was 52% for the period ended April 1, 2010 through June 30,
2010.
General and administrative expenses for the three and six months ended June 30, 2011 was
$18,500 and $42,500, respectively. General and administrative expenses for the period ended April
1, 2010 through June 30, 2010 was $100. These expenses include third-party costs for services as
well as the monthly administrative fees charged by our MGP, and vary from year to year due to the
timing and billing of the costs and services provided to us.
Liquidity and Capital Resources
Cash provided by operating activities increased by $2,263,200 for the six months ended June
30, 2011 as compared to the period ended April 1, 2010 through June 30, 2010. This was due to an
increase in net income before depletion and accretion of $3,642,400. In addition, the change in
accrued liabilities decreased operating cash flows by $3,700 and the change in accounts
receivable-affiliate decreased operating cash flows by $1,375,500 for the six months ended June 30,
2011.
Cash used in investing activities investing activities was $29,800,000 during the period ended
April 1, 2010 through June 30, 2010. This consisted of oil and gas well drilling contracts paid to
the MGP.
Cash used in financing activities was $1,812,600 for the six month period ended June 30, 2011.
This was due to distributions to partners. Cash provided by financing activities was $33,080,800
for the six month period ended June 30, 2010. This was due to Partners capital contributions.
Our MGP may withhold funds for future plugging and abandonment costs. Through June 30, 2011,
our MGP had not withheld any funds for this purpose. 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 any time
exceed 5% of our total subscriptions, and we will not borrow from third-parties.
The Partnership is generally limited to the amount of funds generated by the cash flows from
our operations, which we believe is adequate to fund future operations and distributions to our
partners. Historically, there has been no need to borrow funds from our MGP to fund operations.
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 the benefit of the limited partners
for an amount equal to at least 12% of their net subscriptions in the first 12-month subordination
period, 10% of their net subscriptions in each of the next six 12-month subordination periods, and
8% of their net subscriptions in the fifth 12-month subordination period determined on a cumulative
basis, in each of the first five years of Partnership operations, commencing when the MGP
determines natural gas or oil is being sold from at least 75% of the partnerships wells, excluding
any wells drilled that were non-productive and expiring 60 months from that date. The Partnerships
first distribution was March 2011.
17
Table of Contents
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based
upon our financial statements, which have been prepared in accordance with accounting principles
generally accepted in the United States of America. On an on-going basis, we evaluate our
estimates, including those related to our asset retirement obligations, depletion and certain
accrued receivables and liabilities. We base our estimates on historical experience and on various
other assumptions that we believe reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities that are not readily
apparent from other sources. Actual results may differ from these estimates under different
assumptions or conditions. A discussion of our significant accounting policies we have adopted and
followed in the preparation of our financial statements is included within Notes to Financial
Statements in Part I, Item 1, Financial Statements in this quarterly report and in our Annual
Report on Form 10 for the year ended December 31, 2010.
ITEM 4. | CONTROLS AND PROCEDURES |
Evaluation 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 MGPs 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 MGPs 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 MGPs Chairman of the Board of Directors, Chief Executive
Officer, President and Chief Financial Officer, concluded that, at June 30, 2011, our disclosure
controls and procedures were effective at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
There have been no changes in the Partnerships internal control over financial reporting
during our most recent fiscal quarter that have materially affected, or are reasonably likely to
materially effect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. | LEGAL PROCEEDINGS |
The Managing General Partner is not aware of any legal proceedings filed against the
Partnership.
Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings
arising in the ordinary course of their collective business. The MGPs 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.
18
Table of Contents
ITEM 6. | EXHIBITS |
EXHIBIT INDEX
Exhibit No. | Description | |||
4.0 | Amended and Restated Certificate and Agreement of Limited Partnership for Series 28-2010 L.P. (1) |
|||
31.1 | Certification Pursuant to Rule 13a-14/15(d)-14 |
|||
31.2 | Certification Pursuant to Rule 13a-14/15(d)-14 |
|||
32.1 | Section 1350 Certification |
|||
32.2 | Section 1350 Certification |
|||
101 | Interactive Data File |
(1) | Filed on April 29, 2011 in the Form 10-12G Registration Statement dated April 29, 2011 File No. 000-54378 |
19
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities of the Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Atlas Resources Series 28-2010 L. P.
ATLAS RESOURCES, LLC, Managing General Partner |
||||
Date: August 12, 2011 | 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 person on
behalf of the registrant and in the capacities and on the dates indicated.
Date: August 12, 2011 | By: | /s/ SEAN P. MCGRATH | ||
Sean P. McGrath, Chief Financial Officer |
20