Attached files

file filename
EX-31.1 - CERTIFICATION OF CEO - SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C LPmel3311122331_1.htm
EX-31.2 - CERTIFICATION OF CFO - SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C LPmike3311122331_2.htm
EX-32.1 - CERTIFICATION OF CEO & CFO - SOUTHWEST ROYALTIES INSTITUTIONAL INCOME FUND X-C LPmelmike3311122332_1.htm

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549

(Mark One)

x           QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

OR

¨           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 033-47668-03

Southwest Royalties Institutional Income Fund X-C, L.P.
(Exact name of registrant as specified in
its limited partnership agreement)

Delaware
 
75-2374449
(State or other jurisdiction
 
(I.R.S. Employer
of incorporation or organization)
 
Identification No.)
     
6 Desta Drive, Suite 6500, Midland, Texas
 
79705
(Address of principal executive office)
 
(Zip Code)

(432) 682-6324
(Registrant's telephone number, including area code)

Not applicable
(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether 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:YesxNo¨

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
¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ¨
 
Accelerated filer ¨
 
Non-accelerated filer x
 
Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
¨ Yes
x No

The registrant's outstanding securities consist of Units of limited partnership interests for which there exists no established public market from which to base a calculation of aggregate market value.


 
 

 


 
Table of Contents
 
     
   
Page
 
Glossary                                                                                                             
3
     
 
Part I - FINANCIAL INFORMATION
 
     
Financial Statements                                                                                                             
5
     
 
Balance Sheets as of March 31, 2011 and December 31, 2010                                                                                                             
6
     
 
7
     
 
8
     
11
     
Quantitative and Qualitative Disclosures About Market Risk                                                                                                             
15
     
Controls and Procedures                                                                                                             
15
     
 
Part II – OTHER INFORMATION
 
     
Legal Proceedings                                                                                                             
16
     
Risk Factors                                                                                                             
16
     
Unregistered Sales of Equity Securities and Use of Proceeds                                                                                                             
16
     
Defaults Upon Senior Securities                                                                                                             
16
     
(Removed and Reserved)                                                                                                             
16
     
Other Information                                                                                                             
16
     
Exhibits                                                                                                             
16
     
 
Signatures                                                                                                             
17

 
2

 

Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this filing.  All volumes of natural gas referred to herein are stated at the legal pressure base to the state or area where the reserves exit and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

Bbl. One barrel, or 42 U.S. gallons of liquid volume.

BOE.  Means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis.  Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.

Developmental well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Completion .  The installation of permanent equipment for the production of oil or gas.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Farm-out arrangement. An agreement whereby the owner of a leasehold or working interest agrees to assign his interest in certain specific acreage to an assignee, retaining some interest, such as an overriding royalty interest, subject to the drilling of one (1) or more wells or other specified performance by the assignee.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Mcf. One thousand cubic feet.

Natural gas liquids .  Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

Net Profits Interest.  An agreement whereby the owner receives a specified percentage of the defined net profits from a producing property in exchange for consideration paid.  The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

Oil. Crude oil, condensate and natural gas liquids.

Overriding royalty interest. Interests that are carved out of a working interest, and their duration is limited by the term of the lease under which they are created.

Present value of proved reserves (“PV-10”).   The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

Proved Area. The part of a property to which proved reserves have been specifically attributed.

Proved developed oil and gas reserves. Proved oil and gas reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.


 
3

 

Proved properties. Properties with proved reserves.

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.  (i) The area of the reservoir considered as proved includes:  (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.

Proved undeveloped reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage.  Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure of discounted future net cash flows. Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.  The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

Workover. Operations on a producing well to restore or increase production.



 
4

 

PART I. - FINANCIAL INFORMATION


Financial Statements

The unaudited condensed financial statements included herein have been prepared by the Registrant (herein also referred to as the "Partnership") in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X.  Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements.  In the opinion of management, all adjustments necessary for a fair presentation have been included and are of a normal recurring nature.  The financial statements should be read in conjunction with the audited financial statements and the notes thereto for the year ended December 31, 2010, which are found in the Registrant's Form 10-K Report for 2010 filed with the Securities and Exchange Commission.  The December 31, 2010 balance sheet included herein has been taken from the Registrant's 2010 Form 10-K Report.  Operating results for the three month period ended March 31, 2011 are not necessarily indicative of the results that may be expected for the full year.




 
5

 

Southwest Royalties Institutional Income Fund X-C, L.P.
Balance Sheets



   
March 31,
   
December 31,
 
   
2011
   
2010
 
   
(unaudited)
       
Assets
           
             
Current assets:
           
Cash and cash equivalents
  $ 230,585     $ 152,674  
Receivable from Managing General Partner
    104,554       92,616  
New Mexico income tax deposits
    2,392       1,959  
Total current assets
    337,531       247,249  
                 
Oil and gas properties - using the full-cost
               
method of accounting
    2,766,468       2,766,468  
Less accumulated depreciation,
               
depletion and amortization
    2,410,400       2,401,966  
                 
Net oil and gas properties
    356,068       364,502  
                 
    $ 693,599     $ 611,751  
                 
Liabilities and Partners' Deficit
               
                 
Asset retirement obligation
  $ 1,342,190     $ 1,327,105  
                 
Partners' deficit:
               
General partners
    (89,626 )     (97,146 )
Limited partners
    (558,965 )     (618,208 )
                 
Total partners' deficit
    (648,591 )     (715,354 )
                 
    $ 693,599     $ 611,751  




















The accompanying notes are an integral
part of these financial statements.

 
6

 

Southwest Royalties Institutional Income Fund X-C, L.P.
Statements of Operations
(unaudited)


   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
Revenues
           
             
Income from net profits interests
  $ 147,503     $ 95,114  
Interest
    109       29  
      147,612       95,143  
                 
Expenses
               
                 
Depreciation, depletion and amortization
    8,434       12,221  
Accretion of asset retirement obligations
    27,215       25,738  
General and administrative
    20,200       18,143  
      55,849       56,102  
                 
Net income
  $ 91,763     $ 39,041  
                 
Net income allocated to:
               
                 
Managing General Partner
  $ 9,018     $ 4,613  
                 
General partner
  $ 1,002     $ 513  
                 
Limited partners
  $ 81,743     $ 33,915  
                 
Per limited partner unit
  $ 13.66     $ 5.67  
























The accompanying notes are an integral
part of these financial statements.

 
7

 

Southwest Royalties Institutional Income Fund X-C, L.P.
Statements of Cash Flows
(unaudited)


   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
Cash flows from operating activities:
           
             
Cash received from net profits interest
  $ 123,002     $ 83,692  
Cash paid to suppliers
    (20,200 )     (18,143 )
Interest received
    109       29  
                 
Net cash provided by operating activities
    102,911       65,578  
                 
Cash flows used in financing activities:
               
                 
Distributions to partners
    (25,000 )     (40,000 )
                 
Net increase in cash and cash equivalents
    77,911       25,578  
                 
Beginning of period
    152,674       58,405  
                 
End of period
  $ 230,585     $ 83,983  
                 
Reconciliation of net income to net cash
               
provided by operating activities:
               
                 
Net income
  $ 91,763     $ 39,041  
                 
Adjustments to reconcile net income to
               
net cash provided by operating activities:
               
                 
Depreciation, depletion and amortization
    8,434       12,221  
Accretion of asset retirement obligations
    27,215       25,738  
Settlement of asset retirement obligations
               
for plugged and abandoned wells
    (12,130 )     -  
Increase in receivables and deposits
    (12,371 )     (11,422 )
                 
Net cash provided by operating activities
  $ 102,911     $ 65,578  















The accompanying notes are an integral
part of these financial statements.

 
8

 

Southwest Royalties Institutional Income Fund X-C, L.P.

Notes to Financial Statements

1.
Organization
Southwest Royalties Institutional Income Fund X-C, L.P. was organized under the laws of the state of Delaware on September 20, 1991, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement.  The Partnership sells its oil and gas production to several purchasers with the prices it receives being dependent upon the oil and gas economy.  Southwest Royalties, Inc., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as the Managing General Partner.

Revenues, costs and expenses are allocated as follows:

 
Limited
 
General
 
Partners
 
Partners
Interest income on capital contributions
100%
 
-
Oil and gas sales
90%
 
10%
All other revenues
90%
 
10%
Organization and offering costs (1)
100%
 
-
Syndication costs
100%
 
-
Amortization of organization costs
100%
 
-
Property acquisition costs
100%
 
-
Gain/loss on property disposition
90%
 
10%
Operating and administrative costs (2)
90%
 
10%
Depreciation, depletion and amortization of oil and gas properties
100%
 
-
All other costs
90%
 
10%

 
(1)
All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution.  The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.

 
(2)
Administrative costs in any year, which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.

2.
Summary of Significant Accounting Policies
The interim financial information as of March 31, 2011, and for the three months ended March 31, 2011, is unaudited.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission.  However, in the opinion of management, these interim financial statements include all the necessary adjustments to fairly present the results of the interim periods and all such adjustments are of a normal recurring nature.  The interim consolidated financial statements should be read in conjunction with the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010.




 
9

 

Southwest Royalties Institutional Income Fund X-C, L.P.

Notes to Financial Statements

3.
Abandonment Obligations
The Partnership follows the provisions of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), as amended.  SFAS 143 requires the Partnership to recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset.  The cost associated with the abandonment obligations, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

Our asset retirement obligation is measured using primarily Level 3 inputs.  The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life.  The inputs are calculated based on historical data as well as current estimated costs.

Changes in abandonment obligations for the three months ended March 31, 2011 and 2010 are as follows:

   
2011
   
2010
 
Beginning of period
  $ 1,327,105     $ 1,246,630  
Reduction of obligations due to wells plugged and abandoned
    (12,130 )     -  
Accretion expense
    27,215       25,738  
End of period
  $ 1,342,190     $ 1,272,368  

4.
Subsequent Events
The Partnership has evaluated events and transactions that occurred after the balance sheet date of March 31, 2011.  The Partnership did not have any subsequent events that would require recognition in the financial statements or disclosures in these notes to the financial statements.

 
10

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

General
Southwest Royalties Institutional Income Fund X-C, L.P. was organized as a Delaware limited partnership on September 20, 1991.  The offering of such limited partnership interests began October 1, 1991 as part of a shelf offering registered under the name Southwest Royalties Institutional 1990-91 Income Program.  Minimum capital requirements for the Partnership were met on January 28, 1992, with the offering of limited partnership interests concluding April 30, 1992, with 340 limited partners purchasing 5,983 units for $2,991,500.

The Partnership was formed to acquire royalty and net profits interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties, and to distribute the net proceeds from operations to the limited and general partners.  Net revenues from producing oil and gas properties will not be reinvested in other revenue producing assets except to the extent that production facilities and wells are improved or reworked or where methods are employed to improve or enable more efficient recovery of oil and gas reserves.  The economic life of the Partnership thus depends on the period over which the Partnership’s oil and gas reserves are economically recoverable.

Increases or decreases in Partnership revenues and, therefore, distributions to partners will depend primarily on changes in the prices received for production, changes in volumes of production sold, increases and decreases in production costs, enhanced recovery projects, offset drilling activities pursuant to farm-out arrangements, sales of properties, and the depletion of wells.  Since wells deplete over time, production can generally be expected to decline from year to year.

Production costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately to production volumes or revenues.  Net income available for distribution to the partners is therefore expected to decline in later years based on these factors.

Oil and Gas Properties
The Partnership uses the full cost method of accounting for its oil and gas producing activities.  Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves are capitalized.  Depletion is provided using the unit-of production method based upon estimates of proved oil and gas reserves.  The amortizable base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage value.  All of the Partnership’s oil and gas properties are located within the United States.  Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are sold.

Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of March 31, 2011, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.

The Partnership's interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States.  A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property.  The net profits interest owner will not otherwise participate in additional costs and expenses of the property.

The Partnership recognizes income from its net profits interest in oil and gas property on an accrual basis, while the quarterly cash distributions of the net profits interest are based on a calculation of actual cash received from oil and gas sales, net of expenses incurred during that quarterly period. If the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter, no cash distribution is due to the Partnership's net profits interest until the deficit is recovered from future net profits.  The Partnership accrues a quarterly loss on its net profits interest provided there is a cumulative net amount due for accrued revenue as of the balance sheet date.  As of March 31, 2011, there were no timing differences which resulted in a deficit net profit interest.


 
11

 

Critical Accounting Policies
The Partnership follows the full cost method of accounting for its oil and gas properties.  The full cost method subjects companies to quarterly calculations of a “ceiling”, or limitation on the amount of properties that can be capitalized on the balance sheet.  If the Partnership’s capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense.

The Partnership’s discounted present value of its proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments.  Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures.  The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries.  Different reserve engineers may make different estimates of reserve quantities based on the same data.  The Partnership’s reserve estimates are prepared by outside consultants.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information.  However, there can be no assurance that more significant revisions will not be necessary in the future.  If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown.  In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of depletion, depreciation, and amortization (“DD&A”).

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment.  Current SEC financial accounting and reporting standards require that pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report.  The ceiling calculation dictates that those prices be held constant. Because the ceiling calculation dictates that prices and costs are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves.  Oil and natural gas prices have historically been cyclical and can be either substantially higher or lower than the Partnership’s long-term price forecast that is a barometer for true fair value.



 
12

 

Supplemental Information
The following unaudited information is intended to supplement the financial statements included in this Form 10-Q with data that is not readily available from those statements.

   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
Oil production in barrels
    3,547       3,848  
Gas production in mcf
    2,237       1,291  
Total (BOE)
    3,920       4,063  
Average price per barrel of oil
  $ 91.77     $ 75.99  
Average price per mcf of gas
  $ 6.43     $ 5.72  
Partnership distributions
  $ 25,000     $ 40,000  
Limited partner distributions
  $ 22,500     $ 36,000  
Per unit distribution to limited partners
  $ 3.76     $ 6.02  
Number of limited partner units
    5,983       5,983  

Operating Results
The following discussion compares our results for the quarters ended March 31, 2011 and 2010.  Unless otherwise indicated, references to 2011 and 2010 within this section refer to the respective quarterly period.

Revenues
Comparing 2011 to 2010, oil and gas sales increased $40,094, of which price variances accounted for a $57,555 increase and production variances accounted for a $17,461 decrease.

Production in 2011 (on a BOE basis) was 4% lower than 2010.  Our oil production decreased 8% in 2011 compared to 2010.  Our gas production was 73% higher in 2011 than 2010 due primarily the production increase on two wells.

In 2011, our realized oil price was 21% higher than 2010, while our realized gas price was 12% higher.  Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Oil and gas production costs on a BOE basis decreased from $50.37 per BOE in 2010 to $49.08 per BOE in 2011.

Expenses
Depletion on a BOE basis decreased 28% in 2011.  Comparing 2011 to 2010, depletion expense decreased $3,787, of which rate variances accounted for a $3,356 decrease and production variances accounted for a $431 decrease.

Accretion expense increased 6% in 2011 compared to 2010.

General and administrative (“G&A”) expenses were 11% higher in 2011 due primarily to increases in professional fees and engineering services.

Texas Margin Taxes
In May 2006, the State of Texas adopted House Bill 3, which modified the state’s franchise tax structure, replacing the previous tax based on capital or earned surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax reports filed on or after January 1, 2008. The Texas margin Tax is computed by applying the applicable tax rate (1% for the Partnership’s business) to the profit margin, which is generally determined by total revenue less either cost of goods sold or compensation as applicable. However the Partnership believes, based on its interpretation, that the Texas Margin Tax does not apply to the Partnership since substantially all of its income is derived from a net profits interest.



 
13

 

Liquidity and Capital Resources
Partnership distributions during the quarter ending March 31, 2011 were $25,000, of which $22,500 was distributed to the limited partners and $2,500 to the general partners.  Cumulative cash distributions of $5,912,885 have been made to the general and limited partners as of March 31, 2011.  As of March 31, 2011, $5,338,256 or $892.24 per limited partner unit has been distributed to the limited partners, representing 178% of contributed capital.

The Partnership reported a deficit in partners’ equity of $648,591 at March 31, 2011.  This deficit originated primarily in connection with the recording of asset retirement obligations in accordance with SFAS 143.  Many of the Partnership’s wells are nonproductive and must be plugged in compliance with applicable regulations.  Since the Partnership’s ownership in the wells is structured as a net profits interest, the Partnership is not liable for asset retirement costs except to the extent of its future cash flow.  As costs are incurred to plug and abandon Partnership wells, cash flow from operations will be reduced or eliminated.



 
14

 

Quantitative and Qualitative Disclosures About Market Risk

The Partnership financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control.  These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, trading activities in commodities future markets, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.  The Partnership cannot predict future oil and gas prices with any degree of certainty.  Sustained weakness in oil and gas prices may adversely affect our financial condition, results of operations and cash distributions to partners.

The Partnership is not a party to any derivative or embedded derivative instruments.

Controls and Procedures

Disclosure Controls and Procedures
The Managing General Partner has established disclosure controls and procedures that are adequate to provide reasonable assurance that management of the Managing General Partner will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in the Partnership’s reports to the SEC.  Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to management of the Managing General Partner, including its chief executive and chief financial officers, to allow timely decisions regarding required disclosures.

With respect to these disclosure controls and procedures:

·  
management of the Managing General Partner has evaluated the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report;

·  
this evaluation was conducted under the supervision and with the participation of management of the Managing General Partner, including the chief executive and chief financial officers of the Managing General Partner; and

·  
it is the conclusion of chief executive and chief financial officers of the Managing General Partner that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Partnership in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.

Internal Control Over Financial Reporting
There has not been any change in the Partnership’s internal control over financial reporting that occurred during the quarter ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.



 
15

 

PART II. - OTHER INFORMATION

Legal Proceedings

None

Risk Factors

In evaluating all forward-looking statements, you should specifically consider various factors that may cause actual results to vary from those contained in the forward-looking statements.  Our risk factors are included in our Annual Report on Form 10-K for the year ended December 31, 2010, as filed with the U.S. Securities and Exchange Commission on March 31, 2011 and available at www.sec.gov.  There have been no material changes to these risk factors since the filing of our Form 10-K.

Unregistered Sales of Equity Securities and Use of Proceeds

None

Defaults Upon Senior Securities

None

(Removed and Reserved)

None

Other Information

None


Exhibits

 
(a)
Exhibits:

                   31.1
Rule 13a-14(a)/15d-14(a) Certification
                   31.2
Rule 13a-14(a)/15d-14(a) Certification
                   32.1
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002





 
16

 



Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


 
Southwest Royalties Institutional Income Fund
 
X-C, L.P., a Delaware limited partnership
   
By:
Southwest Royalties, Inc., Managing
 
General Partner
   
   
By:
/s/ Mel G. Riggs
 
Mel G. Riggs
 
President and Chief Executive Officer
   
Date:
May 13, 2011

 
 
17