Item 1. Business.
Cautionary Statement Regarding Forward-Looking Information
Certain statements and information in this Annual Report on Form 10-K ("this report") may constitute "forward-looking statements." The words "believe," "expect," "anticipate," "plan," "intend," "foresee," "should," "would," "could" or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those described in (1) Part I-Item 1A
Item 1A. Risk Factors.
An investment in our securities is subject to certain risks described below. If any of these risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the distributions on our Common Units, the trading price of our Common Units could decline and you could lose part or all of your investment.
Risks Related to Our Business
Oil and natural gas prices and differentials are highly volatile. In the past, declines in commodity prices have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow. A decline in our cash flow could force us to reduce our distributions or cease paying distributions altogether in the future.
The oil and natural gas markets are highly volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
•
domestic and foreign supply of and demand for oil and natural gas;
•
market prices of oil and natural gas;
•
level of consumer product demand;
•
weather conditions;
•
overall domestic and global political and economic conditions;
•
political and economic conditions in oil and natural gas producing countries, including those in the Middle East, Russia, South America and Africa;
•
actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
•
impact of the U.S. dollar exchange rates on oil and natural gas prices;
•
technological advances affecting energy consumption and energy supply;
•
domestic and foreign governmental regulations and taxation;
•
the impact of energy conservation efforts;
•
the capacity, cost and availability of oil and natural gas pipelines, processing, gathering and other transportation facilities, and the proximity of these facilities to our wells;
•
an increase in imports of liquid natural gas in the United States; and
•
the price and availability of alternative fuels.
Oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because natural gas accounted for approximately 65% of our estimated proved reserves as of December 31, 2011 and is a substantial portion of our current production on an Mcfe basis, our financial results will be more sensitive to movements in natural gas prices.
In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2011, the monthly average NYMEX WTI spot price ranged from a low of $86 per barrel in September 2011 to a high of $110 per barrel in April 2011 while the monthly average Henry Hub natural gas price ranged from a low of $3.17 per MMBtu in December to a high of $4.54 per MMBtu in June.
Price discounts or differentials between NYMEX WTI prices and what we actually receive are also historically very volatile. For instance, during calendar year 2011, the average quarterly premium to NYMEX WTI for our California production varied from $5.86 to $20.30 per barrel, with the differential percentage of the total price per barrel ranging from 6% to 22%. For Wyoming crude oil, our average quarterly price discount from NYMEX WTI varied from $9.40 to $21.44, with the discount percentage ranging from 10% to 23% of the total price per barrel. Our crude oil produced from our Florida properties also traded at a significant discount to NYMEX WTI primarily because of its low gravity and other characteristics as well as its distance from a major refining market. For Florida crude oil, our average quarterly discount to NYMEX WTI varied from $10.13 to $16.12 including transportation expenses of approximately $7.50 per barrel, with the discount percentage ranging from 11% to 18% of the total price per barrel.
Our revenue, profitability and cash flow depend upon the prices and demand for oil and natural gas, and a drop in prices could significantly affect our financial results and impede our growth. In particular, continuance of the current low natural gas price environment, further declines in natural gas prices, lack of natural gas storage or a significant decline in crude oil prices will negatively impact:
•
our ability to pay distributions;
•
the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
•
the amount of cash flow available for capital expenditures;
•
our ability to replace our production and future rate of growth;
•
our ability to borrow money or raise additional capital and our cost of such capital;
•
our ability to meet our financial obligations; and
•
the amount that we are allowed to borrow under our credit facilities.
Historically, higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. Accordingly, continued high costs could adversely affect our ability to pursue our drilling program and our results of operations.
In the past, we have raised our distribution levels on our Common Units in response to increased cash flow during periods of relatively high commodity prices. However, we were not able to sustain those distribution levels during subsequent periods of lower commodity prices. For example, our initial distribution rate was $1.65 on an annual basis for the fourth quarter of 2006. The distribution made to our unitholders on February 13, 2009 for the fourth quarter of 2008 was $2.08 on an annual basis. As a result of the reduction in our borrowing base in April 2009, we were restricted from declaring a distribution on our Common Units and did not pay a distribution from February 2009 until May 2010. Although distributions were reinstated in 2010, a decline in our cash flow may force us to reduce our distributions or cease paying distributions again altogether in the future.
Natural gas prices have declined substantially in the last year, and are expected to remain depressed for the foreseeable future. Approximately 54% of our 2011 production, on an MBoe basis, is natural gas. Sustained depressed prices of natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially.
Natural gas prices have declined from a monthly average price for Henry Hub of $4.49 per MMBtu in January 2011 to $2.67 per MMBtu in January 2012 and $2.48 for the first three weeks of February 2012. The reduction in prices has been caused by many factors, including recent increases in gas production from non-conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. We have hedged more than 65% of our natural gas production in 2012 and 2013 at prices higher than those currently prevailing. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and gas properties and/or revise our development plans which may cause certain of our undeveloped well locations to no longer be deemed to be proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses, make distributions to our unitholders and to service our indebtedness.
The continuing decline of natural gas prices and concern about the global financial markets could limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, obtain additional or continued funding under our current credit facility or obtain funding at all.
Following the 2008 economic downturn, global financial markets, economic conditions and commodity prices were disrupted and volatile. In addition, the debt and equity capital markets were slow to recover. A continued decline in natural gas prices and concern about the global financial markets could make it challenging to obtain funding in the capital and credit markets in the future. During 2011 and the first quarter of 2012, we were able to access the debt and equity capital markets. However, the continuing decline of natural gas prices could significantly increase the cost of obtaining money from the capital and credit markets and limit our ability to access those markets as a source of funding.
Historically, we have used our cash flow from operations, borrowings under our credit facility and issuance of senior notes and additional partnership units to fund our capital expenditures and acquisitions. The continuing decline of natural gas prices could ultimately decrease our net revenue and profitability. The recent natural gas price declines have negatively impacted our revenues and cash flows.
These events affect our ability to access capital in a number of ways, which include the following:
•
Our ability to access new debt or credit markets on acceptable terms may be limited and this condition may last for an unknown period of time.
•
Our current credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria.
•
We may be unable to obtain adequate funding under our current credit facility because our lenders may simply be unwilling or unable to meet their funding obligations.
•
The operating and financial restrictions and covenants in our credit facility limit (and any future financing agreements likely will limit) our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions.
Due to these factors, we cannot be certain that funding will be available, if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, financial condition or ability to pay distributions. Moreover, if we are unable to obtain funding to make acquisitions of additional properties containing proved oil or natural gas reserves, our total level of proved reserves may decline as a result of our production, and we may be limited in our ability to maintain our level of cash distributions.
Even if we are able to pay quarterly distributions on our Common Units under the terms of our credit facility, we may not elect to pay quarterly distributions on our Common Units because we do not have sufficient cash flow from operations following establishment of cash reserves, reduction of debt and payment of fees and expenses.
Our credit facility limits the amounts we can borrow to a borrowing base amount, which is determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. For example, in April 2009, our borrowing base was decreased from $900 million to $760 million as a result of a scheduled borrowing base redetermination and further decreased to $732 million as a result of an asset sale and derivative contract monetization. In October 2011, our borrowing base was increased to $850 million and in January 2012 reduced to $788 million as a result of our issuance of $250 million in aggregate principal amount of unsecured 7.875% senior notes maturing April 15, 2022 (the “2022 Senior Notes”). As a result of the reduction in our borrowing base in April 2009, we were restricted from declaring a distribution on our Common Units and did not pay a distribution from February 2009 until May 2010. While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again be restricted from paying a distribution in the future. Our credit facility restricts our ability to make distributions to unitholders or repurchase units unless after giving effect to such distribution or repurchase, we remain in compliance with all terms and conditions of our credit facility.
Even if we are able to pay quarterly distributions on our Common Units under the terms of our credit facility, we may not have sufficient available cash each quarter to pay quarterly distributions on our Common Units. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses, debt reduction and the amount of any cash reserve amounts that our General Partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our unitholders. In the future, we may reserve a substantial portion of our cash generated from operations to develop our oil and natural gas properties and to acquire additional oil and natural gas properties in order to maintain and grow our level of oil and natural gas reserves.
The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including among other things:
•
the amount of oil and natural gas we produce;
•
demand for and prices at which we sell our oil and natural gas;
•
the effectiveness of our commodity price derivatives;
•
the level of our operating costs;
•
prevailing economic conditions;
•
our ability to replace declining reserves;
•
continued development of oil and natural gas wells and proved undeveloped reserves;
•
our ability to acquire oil and natural gas properties from third parties in a competitive market and at an attractive price;
•
the level of competition we face;
•
fuel conservation measures;
•
alternate fuel requirements;
•
government regulation and taxation; and
•
technical advances in fuel economy and energy generation devices.
In addition, the actual amount of cash that we will have available for distribution will depend on other factors, including:
•
our ability to borrow under our credit facility to pay distributions;
•
debt service requirements and restrictions on distributions contained in our credit facility or future debt agreements;
•
the level of our capital expenditures;
•
sources of cash used to fund acquisitions;
•
fluctuations in our working capital needs;
•
general and administrative expenses;
•
cash settlement of hedging positions;
•
timing and collectability of receivables; and
•
the amount of cash reserves established for the proper conduct of our business.
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Part II-Item 7 "-Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources."
If we do not make acquisitions on economically acceptable terms, our future growth and ability to pay or increase distributions will be limited.
Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because:
•
we cannot identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
•
we cannot obtain financing for these acquisitions on economically acceptable terms;
•
we are outbid by competitors; or
•
our Common Units are not trading at a price that would make the acquisition accretive.
If we are unable to acquire properties containing proved reserves, our total level of estimated proved reserves may decline as a result of our production, and we may be limited in our ability to increase or maintain our level of cash distributions.
Any acquisitions that we complete are subject to substantial risks that could reduce our ability to make distributions to our unitholders. The integration of the oil and natural gas properties that we acquire may be difficult, and could divert our management's attention away from our other operations.
If we do make acquisitions that we believe will increase available cash per unit, these acquisitions may nevertheless result in a decrease in available cash per unit. Any acquisition involves potential risks, including, among other things:
•
the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
•
an inability to integrate successfully the businesses we acquire;
•
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
•
a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•
the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
•
the diversion of management's attention from other business concerns;
•
an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
•
the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
•
unforeseen difficulties encountered in operating in new geographic areas; and
•
customer or key employee losses at the acquired businesses.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.
Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
Drilling for and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders.
The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough oil and natural gas to be commercially viable after drilling, operating and other costs. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
•
high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
•
unexpected operational events and drilling conditions;
•
reductions in oil and natural gas prices;
•
limitations in the market for oil and natural gas;
•
problems in the delivery of oil and natural gas to market;
•
adverse weather conditions;
•
facility or equipment malfunctions;
•
equipment failures or accidents;
•
title problems;
•
pipe or cement failures;
•
casing collapses;
•
compliance with environmental and other governmental requirements;
•
environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
•
lost or damaged oilfield drilling and service tools;
•
unusual or unexpected geological formations;
•
loss of drilling fluid circulation;
•
pressure or irregularities in formations;
•
fires, blowouts, surface craterings and explosions;
•
natural disasters; and
•
uncontrollable flows of oil, natural gas or well fluids.
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
We may be unable to compete effectively with other companies in the oil and gas industry, which may adversely affect our ability to generate sufficient revenue to allow us to pay distributions to our unitholders.
The oil and gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major independent oil and gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties and available funds. Many of our larger competitors not only drill for and produce oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and gas industry. Other companies may have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with other companies could have a material adverse effect on our business activities, financial condition and results of operations.
Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
As of February 28, 2012, we had approximately $88.0 million in borrowings outstanding under our credit facility. Our credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined semi-annually and the available borrowing amount could be further decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements or regulations or certain other circumstances. In October 2011, our borrowing base was increased to $850 million from $735 million and in January 2012 was reduced to $788 million as a result of our issuance of the 2022 Senior Notes. Our next borrowing base redetermination will be in April 2012. As a result of the continuing decline in natural gas prices, our borrowing base could be decreased by the lenders under our credit facility. A future decrease in our borrowing base could be substantial and could be to a level below our outstanding borrowings at that time. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility or sell assets or debt or Common Units. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in a default under our credit facility, which could adversely affect our business, financial condition and results of operations.
The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:
•
incur indebtedness;
•
grant liens;
•
make certain acquisitions and investments;
•
lease equipment;
•
make capital expenditures above specified amounts;
•
redeem or prepay other debt;
•
make distributions to unitholders or repurchase units;
•
enter into transactions with affiliates; and
•
enter into a merger, consolidation or sale of assets.
Our credit facility restricts our ability to make distributions to unitholders or repurchase Common Units unless after giving effect to such distribution or repurchase, we remain in compliance with all terms and conditions of our credit facility. While we currently are not restricted by our credit facility from declaring a distribution as we were in April 2009, we may again be restricted from paying a distribution in the future.
We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. In light of persistent weak economic conditions and the deterioration of natural gas prices, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited and our lenders' commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.
See Part II-Item 7 "-Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources" for a discussion of our credit facility covenants.
Restrictive covenants under our indenture governing our senior notes may adversely affect our operations.
The indentures governing our $305 million unsecured 8.625% senior notes maturing October 15, 2020 (the "2020 Senior Notes") and our 2022 Senior Notes (together the “Senior Notes”) contain, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
•
sell assets, including equity interests in our restricted subsidiaries;
•
pay distributions on, redeem or repurchase our units or redeem or repurchase our subordinated debt;
•
make investments;
•
incur or guarantee additional indebtedness or issue preferred units;
•
create or incur certain liens;
•
enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
•
consolidate, merge or transfer all or substantially all of our assets;
•
engage in transactions with affiliates;
•
create unrestricted subsidiaries; and
•
engage in certain business activities.
As a result of these covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
A failure to comply with the covenants in the indenture governing our senior notes or any future indebtedness could result in an event of default under the indenture governing the Senior Notes or the future indebtedness, which, if not cured or waived, could have a material adverse affect on our business, financial condition and results of operations. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.
As of February 28, 2012, our long-term debt totaled $643 million. Our existing and future indebtedness could have important consequences to us, including:
•
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us;
•
covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;
•
our access to the capital markets may be limited;
•
our borrowing costs may increase;
•
we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and
•
our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.
Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.
We will require substantial capital expenditures to replace our production and reserves, which will reduce our cash available for distribution. We may be unable to obtain needed capital due to our financial condition, which could adversely affect our ability to replace our production and estimated proved reserves.
To fund our capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional partnership interests, or some combination thereof. In 2012, our oil and gas capital spending program is expected to be approximately $68 million, compared to approximately $75 million in 2011 and approximately $70 million in 2010. Based on the continuing decline of natural gas prices, we will continue to evaluate our capital spending program throughout 2012. We expect to use cash generated from operations to fund future capital expenditures, which will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital and credit markets for future equity or debt offerings to fund future capital expenditures was limited in 2009 because of the credit crisis and turmoil in the financial markets. In the future, our ability to borrow and to access the capital and credit markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our debt agreements, as well as by oil and natural gas prices, the value and performance of our equity securities, and adverse market conditions resulting from, among
other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to pay distributions. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional partnership interests may result in significant unitholder dilution, thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate, which could have a material adverse effect on our ability to pay distributions at the then-current distribution rate.
Our inability to replace our reserves could result in a material decline in our reserves and production, which could adversely affect our financial condition. We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base.
Producing oil and natural gas reservoirs are characterized by declining production rates that vary based on reservoir characteristics and other factors. The rate of decline of our reserves and production included in our reserve report at December 31, 2011 will change if production from our existing wells declines in a different manner than we have estimated and may change when we drill additional wells, make acquisitions and under other circumstances. Our future oil and natural gas reserves and production and our cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution.
We are unlikely to be able to sustain or increase distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. We will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce indebtedness until we make the capital expenditures.
Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. If we do not make sufficient growth capital expenditures, we will be unable to sustain our business operations and therefore will be unable to maintain our current level of distributions. With our reserves decreasing, if we do not reduce our distributions, then a portion of the distributions may be considered a return of part of your investment in us as opposed to a return on your investment. Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise the level of future distributions.
Future oil and natural gas price declines may result in a write-down of our asset carrying values.
Declines in oil and natural gas prices in 2008 resulted in us having to make substantial downward adjustments to our estimated proved reserves resulting in increased depletion and depreciation charges. Accounting rules require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. For example, as a result of the dramatic declines in oil and gas prices in the second half of 2008 and related reserve reductions, we recorded non-cash charges of $51.9 million for total impairments and $34.5 million for price related adjustments to depletion and depreciation expense for the year ended December 31, 2008. We also may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.
Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently and may in the future enter into derivative arrangements for a significant portion of our expected oil and natural gas production that could result in both realized and unrealized hedging losses. As of February 28, 2012, we had hedged, through swaps, options (including collar instruments) and physical contracts, approximately 75% of our 2012 production.
The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are primarily based on IPE Brent, NYMEX WTI and MichCon City-Gate-Inside FERC prices, which may differ significantly from the actual crude oil and natural gas prices we realize in our operations. Furthermore, we have adopted a policy that requires, and our credit facility also mandates, that we enter into derivative transactions related to only a portion of our expected production volumes and, as a result, we will continue to have direct commodity price exposure on the portion of our production volumes not covered by these derivative transactions.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution in our profitability and liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows.
In addition, our derivative activities are subject to the following risks:
•
we may be limited in receiving the full benefit of increases in oil and natural gas prices as a result of these transactions;
•
a counterparty may not perform its obligation under the applicable derivative instrument or seek bankruptcy protection;
•
there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
•
the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.
As of February 28, 2012, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank. We periodically obtain credit default swap information on our counterparties. As of December 31, 2011 and February 28, 2012, each of these financial institutions had an investment grade credit rating. Although we currently do not believe that we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to default. As of December 31, 2011, our largest derivative asset balances were with JP Morgan Chase Bank N.A., Union Bank N.A and Wells Fargo Bank National Association which accounted for approximately 37%, 10% and 10% of our derivative asset balances, respectively. As of December 31, 2011, our largest derivative liability balances were with BNP Paribas, The Royal Bank of Scotland plc and Citibank, N.A. which accounted for approximately 34%, 31% and 22% of our derivative liability balances, respectively.
The adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
Congress adopted comprehensive financial reform legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act ("Dodd-Frank") that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Partnership, that participate in that market. Dodd-Frank was signed into law by the President on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. In its rulemaking under Dodd-Frank, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. Dodd-Frank may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. Dodd-Frank may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as credit worthy as the current counterparty. Dodd-Frank and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less credit worthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more
volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and make distributions to our unitholders. Finally, this legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of Dodd-Frank and any new regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, our results of operations and our ability to make distributions to unitholders.
Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.
It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. Our independent reserve engineers do not independently verify the accuracy and completeness of information and data furnished by us. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to:
•
future oil and natural gas prices;
•
production levels;
•
capital expenditures;
•
operating and development costs;
•
the effects of regulation;
•
the accuracy and reliability of the underlying engineering and geologic data; and
•
the availability of funds.
If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly. For example, if the SEC prices used for our December 31, 2011 reserve report had been $10.00 less per Bbl and $1.00 less per MMBtu, respectively, then the standardized measure of our estimated proved reserves as of December 31, 2011 would have decreased by $423.9 million, from $1,659.3 million, to $1,235.4 million.
Our standardized measure is calculated using unhedged oil prices and is determined in accordance with SEC rules and regulations. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual drilling and production.
The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.
The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
•
the actual prices we receive for oil and natural gas;
•
our actual operating costs in producing oil and natural gas;
•
the amount and timing of actual production;
•
the amount and timing of our capital expenditures;
•
supply of and demand for oil and natural gas; and
•
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with the FASB Accounting Standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
Our actual production could differ materially from our forecasts.
From time to time, we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts assume that none of the risks associated with our oil and gas operations summarized in this Item 1A occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.
In 2011, we depended on four customers for a substantial amount of our sales. If these customers reduce the volumes of oil and natural gas that they purchase from us, our revenue and cash available for distribution will decline to the extent we are not able to find new customers for our production. In addition, if the parties to our purchase contracts default on these contracts, we could be materially and adversely affected.
In 2011, four customers accounted for approximately 70% of our net sales revenues. If these customers reduce the volumes of oil and natural gas that they purchase from us and we are not able to find new customers for our production, our revenue and cash available for distribution will decline. In 2011, ConocoPhillips in California and Michigan accounted for approximately 30% of our net sales revenues, Plains Marketing & Transportation LLC in Florida accounted for approximately 16% of our net sales revenues, Marathon Oil Company in Wyoming accounted for approximately 15% of our net sales revenues and Sunoco Partners Marketing and Terminals L.P. in Michigan accounted for approximately 9% of our net sales revenues. In 2010, ConocoPhillips accounted for approximately 30% of our net sales revenues, Marathon Oil Company accounted for approximately 16% of our net sales revenues, Plains Marketing & Transportation LLC accounted for approximately 12% of our net sales revenues and Sunoco Partners Marketing and Terminals L.P. accounted for approximately 10% of our net sales revenues.
Natural gas purchase contracts account for a significant portion of revenues relating to our Michigan, Indiana and Kentucky properties. We cannot assure you that the other parties to these contracts will continue to perform under the contracts. If the other parties were to default after taking delivery of our natural gas, it could have a material adverse effect on our cash flows for the period in which the default occurred. A default by the other parties prior to taking delivery of our natural gas could also have a material adverse effect on our cash flows for the period in which the default occurred depending on the prevailing market prices of natural gas at the time compared to the contractual prices.
We have limited control over the activities on properties we do not operate.
On a net production basis, we operate approximately 87% of our production as of December 31, 2011. We have limited ability to influence or control the operation or future development of the non-operated properties in which we have interests or the amount of capital expenditures that we are required to fund for their operation. The success and timing of drilling development or production activities on properties operated by others depend upon a number of factors that are outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, approval of other participants, and selection of technology. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could have a material adverse effect on the realization of our targeted returns on capital or lead to unexpected future costs.
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
There are a variety of operating risks inherent in our wells, gathering systems, pipelines and other facilities, such as leaks, explosions, fires, mechanical problems and natural disasters including earthquakes and tsunamis, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
We currently possess property and general liability insurance at levels that we believe are appropriate; however, we are not fully insured for these items and insurance against all operational risk is not available to us. We are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be
available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and recent natural disasters have made it more difficult for us to obtain certain types of coverage. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.
If third-party pipelines and other facilities interconnected to our wells and gathering and processing facilities become partially or fully unavailable to transport natural gas, oil or NGLs, our revenues and cash available for distribution could be adversely affected.
We depend upon third party pipelines and other facilities that provide delivery options to and from some of our wells and gathering and processing facilities. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party pipelines and other facilities become partially or fully unavailable to transport natural gas, oil or NGLs, or if the gas quality specifications for the natural gas gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.
For example, in Florida, there are a limited number of alternative methods of transportation for our production, and substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in us having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production in Florida, which could have a negative impact on our future consolidated financial position, results of operations or cash flows.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.
Our oil and natural gas exploration, production, gathering and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws, including tax laws, and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For example, in California, there have been proposals at the legislative and executive levels in the past two years for tax increases which have included a severance tax as high as 12.5% on all oil production in California. Although the proposals have not passed the California Legislature, the financial crisis in the State of California could lead to a severance tax on oil being imposed in the future. We have significant oil production in California and while we cannot predict the impact of such a tax without having more specifics, the imposition of such a tax could have severe negative impacts on both our willingness and ability to incur capital expenditures in California to increase production, could severely reduce or completely eliminate our California profit margins and would result in lower oil production in our California properties due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously been the case. On the local level, the City of Los Angeles placed an initiative on the March 2011 ballot proposing to increase the city's tax on oil production in the City of Los Angeles to $1.44 per barrel which was defeated. There also is currently proposed federal legislation in three areas (tax legislation, climate change and hydraulic fracturing) that if adopted could significantly affect our operations. The following are brief descriptions of the proposed laws:
•
Tax Legislation. The Fiscal Year 2013 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of such U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our Common Units.
•
Climate Change Legislation and Regulation. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other "greenhouse gases" present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA's rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. California has been one of the leading states in adopting greenhouse gas emission reduction requirements, and California's initial cap and trade program will begin in 2012. Producers and distributors of liquid fuels and natural gas are not subject to emission limits until 2015.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
•
Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and
final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms. Significant restrictions on hydraulic fracturing activities could eventually reduce the amount of oil and natural gas that we are able to produce from our reserves.
•
A change in the jurisdictional characterization of our gathering assets by federal, state or local regulatory agencies or a change in policy by those agencies with respect to those assets may result in increased regulation of those assets.
Failure to comply with federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you. Please read Part I-Item 1 "-Business-Environmental Matters and Regulation" and "-Business-Other Regulation of the Oil and Gas Industry" for a description of the laws and regulations that affect us.
Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and natural gas exploration and production activities. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to make distributions to you could be adversely affected. Please read Part I-Item 1 "Business-Environmental Matters and Regulation" for more information.
We depend on our General Partner's executive officers, who would be difficult to replace.
We depend on the performance of our General Partner's executive officers, Randall Breitenbach and Halbert Washburn. We do not maintain key person insurance for Mr. Breitenbach or Mr. Washburn. The loss of either or both of Mr. Breitenbach or Mr. Washburn could negatively impact our ability to execute our strategy and our results of operations.
Risks Related to Our Structure
We may issue additional Common Units without your approval, which would dilute your existing ownership interests.
We may issue an unlimited number of limited partner interests of any type, including Common Units, without the approval of our unitholders, including in connection with potential acquisitions of oil and gas properties or the reduction of debt, which would dilute your existing ownership interests. For example, in 2007, we issued a total of 45 million Common Units (or 67% of our outstanding Common Units) in connection with our acquisitions of oil and natural gas properties, in February 2011, we issued 4.9 million Common Units (or approximately 9% of our outstanding Common Units at issuance) and in February 2012, we issued 9.2 million Common Units (or approximately 15% of our outstanding Common Units at issuance).
The issuance of additional Common Units or other equity securities may have the following effects:
•
your proportionate ownership interest in us may decrease;
•
the amount of cash distributed on each Common Unit may decrease;
•
the relative voting strength of each previously outstanding Common Unit may be diminished;
•
the market price of the Common Units may decline; and
•
the ratio of taxable income to distributions may increase.
Our partnership agreement limits our General Partner's fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our General Partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
•
provides that our General Partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership;
•
generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the Board and not involving a vote of unitholders will not constitute a breach of our partnership agreement or of any fiduciary duty if they are on terms no less favorable to us than those generally provided to or available from unrelated third parties or are "fair and reasonable" to us and that, in determining whether a transaction or resolution is "fair and reasonable," our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
•
provides that in resolving conflicts of interest where approval of the conflicts committee of the Board is not sought, it will be presumed that in making its decision the Board acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us challenging such approval, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and
•
provides that our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.
Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.
Certain of the directors and officers of our General Partner, including our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, BreitBurn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. Our partnership agreement limits the remedies available to you in the event you have a claim relating to conflicts of interest.
Certain of the directors and officers of our General Partner, including our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, BreitBurn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. We have entered into an Omnibus Agreement with PCEC to address certain of these conflicts. However, these persons may face other conflicts between their interests in PCEC and their positions with us. These potential conflicts include, among others, the following situations:
•
Our General Partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities, cash reserves and expenses. Although we have entered into a new Omnibus Agreement with PCEC, which addresses the rights of the parties relating to potential business opportunities, conflicts of interest may still arise with respect to the pursuit of such business opportunities. We have agreed in the Omnibus Agreement that PCEC and its affiliates will have a preferential right to acquire any third party upstream oil and natural gas properties that are estimated to contain less than 70% proved developed reserves.
•
Currently and historically some officers of our General Partner and many employees of BreitBurn Management have also devoted time to the management of PCEC. This arrangement will continue under the Second Amended and Restated Administrative Services Agreement and this will continue to result in material competition for the time and effort of the officers of our General Partner and employees of BreitBurn Management who provide services to PCEC and who are officers and directors of the sole member of the general partner of PCEC. If the officers of our General Partner and the employees of BreitBurn Management do not devote sufficient attention to the management and operation of our business, our financial results could suffer and our ability to make distributions to our unitholders could be reduced.
See "BreitBurn Management" in Part II-Item 7 "-Management’s Discussion and Analysis of Financial Condition and
Results of Operations" in this report for a discussion of Pacific Coast Oil Trust.
Our partnership agreement limits the liability and reduces the fiduciary duties of our General Partner and its directors and officers, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing Common Units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our Common Units.
Our partnership agreement restricts unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board, cannot vote on any matter. In addition, solely with respect to the election of directors, our partnership agreement provides that (x) our General Partner and the Partnership will not be entitled to vote their units, if any, and (y) if at any time any person or group beneficially owns 20% or more of the outstanding Partnership securities of any class then outstanding and otherwise entitled to vote, then all Partnership securities owned by such person or group in excess of 20% of the outstanding Partnership securities of the applicable class may not be voted, and in each case, the foregoing units will not be counted when calculating the required votes for such matter and will not be deemed to be outstanding for purposes of determining a quorum for such meeting. Such Common Units will not be treated as a separate class of Partnership securities for purposes of our partnership agreement. Notwithstanding the foregoing, the Board may, by action specifically referencing votes for the election of directors, determine that the limitation set forth in clause (y) above will not apply to a specific person or group. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders' ability to influence the manner or direction of management.
Our partnership agreement has provisions that discourage takeovers.
Certain provisions of our partnership agreement may have the effect of delaying or preventing a change in control. Our directors are elected to staggered terms. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our General Partner. The provisions contained in our partnership agreement, alone or in combination with each other, may discourage transactions involving actual or potential changes of control.
Unitholders who are not "Eligible Holders" will not be entitled to receive distributions on or allocations of income or loss on their Common Units and their Common Units will be subject to redemption.
In order to comply with U.S. laws with respect to the ownership of interests in oil and gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our Common Units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and gas leases on federal lands. As of the date hereof, Eligible Holder means: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; or (3) an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof. For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof and only for so long as the alien is not from a country that the United States federal government regards as denying similar privileges to citizens or corporations of the United States. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder will not be entitled to receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.
We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.
Unitholders may not have limited liability if a court finds that unitholder action constitutes participation in control of our business.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:
•
we were conducting business in a state but had not complied with that particular state's partnership statute; or
•
your right to act with other unitholders to elect the directors of our General Partner, to remove or replace our General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted participation in "control" of our business.
Unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of Common Units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the Partnership that are known to such purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.
Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If we were to be treated as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in our Common Units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service ("IRS") with respect to our treatment as a partnership for federal income tax purposes.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, treatment of us as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and, therefore, result in a substantial reduction in the value of our units.
Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships and limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of such a tax on us by any such state will reduce the cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our Common Units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our Common Units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of
Congress have considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the legislation considered would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our Common Units.
If the IRS contests the federal income tax positions we take, the market for our Common Units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our Common Units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.
You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.
Because you will be treated as a partner in us for federal income tax purposes we will allocate a share of our taxable income to you, and you will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive a cash distribution from us. You may not receive a cash distribution from us equal to your share of our taxable income or even equal to the actual tax liability which results from your share of our taxable income.
Tax gain or loss on the disposition of our Common Units could be more or less than expected because prior distributions in excess of allocations of income will decrease your tax basis in your Common Units.
If you sell any of your Common Units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those Common Units. Prior distributions to you in excess of the total net taxable income you were allocated for a Common Unit, which decreased your tax basis in that Common Unit, will, in effect, become taxable income to you if the Common Unit is sold at a price greater than your tax basis in that Common Unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you due to potential recapture of depreciation deductions. In addition, because the amount realized will include your share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our Common Units that may result in adverse tax consequences to them.
Investment in units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Our partnership agreement generally prohibits non-U.S. persons from owning our units. However, if non-U.S. persons own our units, distributions to such non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and such non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our Common Units.
We will treat each purchaser of our Common Units as having the same tax benefits without regard to the Common Units purchased. The IRS may challenge this treatment, which could adversely affect the value of the Common Units.
Due to a number of factors including our inability to match transferors and transferees of Common Units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of Common Units and could have a negative impact on the value of our Common Units or result in audits of and adjustments to our unitholders' tax returns.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the
date a particular Common Unit is transferred. The IRS may challenge this treatment, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our Common Units each month based upon the ownership of our Common Units on the first day of each month, instead of on the basis of the date a particular Common Unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS, were to successfully challenge this method or new Treasury Regulations were issued, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax it ems among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.
A unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose units are loaned to a "short seller" to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder's taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to its unitholders for the tax year in which the termination occurs.
For example, in 2011 as a result of Quicksilver selling approximately 15.7 million of our Common Units together with normal trading activity by other unitholders, greater than 50% of our Common Units traded within a twelve month period and caused a technical termination of the Partnership for federal income tax purposes. This technical termination required the closing of our taxable year for all unitholders on November 30, 2011, and brought about two taxable periods for 2011: January 1, 2011, to November 30, 2011 and December 1, 2011, to December 31, 2011. We will be required to file two tax returns and, unless relief is granted by the IRS, issue two Schedules K-1 to each unitholder. See Note 12 to the consolidated financial statements in this report for further details about this technical termination that occurred in 2011.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
The Fiscal Year 2013 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress which would implement many of these proposals. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and
development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could increase the taxable income allocable to our unitholders and negatively impact the value of an investment in our Common Units.
You may be subject to state and local taxes and return filing requirements.
In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We currently conduct business and own property in California, Florida, Indiana, Kentucky, Michigan, and Wyoming. Each of these states other than Wyoming and Florida currently imposes a personal income tax on individuals, and all of these states impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. Some of the states may require us, or we may elect to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholder's income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to common unitholders for purposes of determining the amounts distributed by us. It is the responsibility of each unitholder to file all U.S. federal, state and local returns that may be required of such unitholder.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
The information required to be disclosed in this Item 2 is incorporated herein by reference to Part I-Item 1 "-Business."
Item 3.
Item 3. Legal Proceedings.
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material pending legal proceedings or know of any such procedures contemplated by government authorities. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.
Item 4.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our Common Units trade on the NASDAQ Global Select Market under the symbol "BBEP." As of December 31, 2011, based upon information received from our transfer agent and brokers and nominees, we had approximately 40,000 common unitholders of record.
The following table sets forth high and low sales prices per Common Unit and cash distributions to common unitholders for the periods indicated. The last reported sales price for our Common Units on the NASDAQ on February 28, 2012 was $19.24 per unit.
We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit agreement restricts us from making cash distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility. See Item 7 "-Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Credit Facility" and Note 10 to the consolidated financial statements in this report.
For the quarters for which we declare a distribution, distributions of available cash are made within 45 days after the end of the quarter to unitholders of record on the applicable record date. Available cash, as defined in our partnership agreement, generally is all cash on hand, including cash from borrowings, at the end of the quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs.
Equity Compensation Plan Information
See Part III-Item 12 "-Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters" for information regarding securities authorized for issuance under equity compensation plans.
Unregistered Sales of Equity Securities and Use of Proceeds
There were no unregistered sales of equity securities during the fourth quarter of 2011.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
There were no purchases of our Common Units by us or any affiliated purchasers during the fourth quarter of 2011.
Common Unit Performance Graph
The graph below compares our cumulative total unitholder return on our Common Units over the past five years, with the cumulative total returns over the same period of the Russell 2000 index and the Alerian MLP index. The graph assumes that the value of the investment in our Common Units, in the Russell 2000 index, and in the Alerian MLP index was $100 on December 31, 2006. Cumulative return is computed assuming reinvestment of dividends.
Comparison of Cumulative Total Return among the Partnership, the Russell 2000 Index and the Alerian MLP Index
The information in this report appearing under the heading "Common Unit Performance Graph" is being furnished pursuant to Item 2.01(e) of Regulation S-K and shall not be deemed to be "soliciting material" or to be "filed" with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
Item 6.
Item 6. Selected Financial Data.
Set forth below is selected historical consolidated financial data for the past five years.
The selected consolidated financial data presented is derived from our audited financial statements. In 2007, we completed seven acquisitions totaling approximately $1.7 billion, the largest of which was the Quicksilver Acquisition for approximately $1.46 billion. In 2008, we acquired Provident’s interest in BreitBurn Management, BreitBurn Corporation contributed its interest in BreitBurn Management to us, and BreitBurn Management contributed its interest in the General Partner to us, resulting in BreitBurn Management and the General Partner becoming our wholly owned subsidiaries. In 2009, we completed the sale of the Lazy JL field for $23 million in cash. In 2011, we completed the Greasewood Acquisition on July 28, 2011, with an effective date of July 1, 2011, for approximately $57 million and the Cabot Acquisition on October 6, 2011 with an effective date of September 1, 2011, for approximately $281 million.
You should read the following selected financial data in conjunction with Part II-Item 7
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis should be read in conjunction with the "Selected Financial Data" and the financial statements and related notes included elsewhere in this report. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences are discussed in "Risk Factors" contained in Part I-Item 1A of this report. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statement Regarding Forward-Looking Information" in the front of this report.
Executive Overview
We are an independent oil and gas partnership focused on the acquisition, exploitation and development of oil and gas properties in the United States. Our objective is to manage our oil and gas producing properties for the purpose of generating cash flow and making distributions to our unitholders. Our assets consist primarily of producing and non-producing crude oil and natural gas reserves located primarily in the Antrim Shale and other non-Antrim formations in Michigan, the Evanston and Green River Basins in southwestern Wyoming, the Wind River and Big Horn Basins in central Wyoming, the Powder River Basin in eastern Wyoming, the Los Angeles Basin in California, the Sunniland Trend in Florida and the New Albany Shale in Indiana and Kentucky.
Our core investment strategy includes the following principles:
•
Acquire long-lived assets with low-risk exploitation and development opportunities;
•
Use our technical expertise and state-of-the-art technologies to identify and implement successful exploitation techniques to optimize reserve recovery;
•
Reduce cash flow volatility through commodity price and interest rate derivatives; and
•
Maximize asset value and cash flow stability through operating and technical expertise.
Acquisitions
On July 28, 2011, we completed the Greasewood Acquisition to acquire crude oil properties in Niobrara County, Wyoming with a July 1, 2011 effective date. The purchase price for the acquisition was approximately $57 million in cash. The properties produced approximately 605 Bbl/d of crude oil in the fourth quarter of 2011.
On October 6, 2011, we completed the Cabot Acquisition to acquire oil and gas properties located primarily in the Evanston and Green River Basins in southwestern Wyoming with a September 1, 2011 effective date for approximately $281 million in cash, subject to ordinary adjustments. The Cabot Assets also include limited acreage and non-operated oil and gas interests in Colorado and Utah. The properties produced approximately 25.7 MMcfe/d in the fourth quarter of 2011 and are 95% natural gas.
We used borrowings under our credit facility to fund both the Greasewood and Cabot Acquisitions.
Highlights
On February 11, 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25, resulting in proceeds net of underwriting discount and expenses of $100 million, which we used to repay outstanding debt under our credit facility.
On February 11, 2011, we paid a cash distribution to unitholders for the fourth quarter of 2010 at the rate of $0.4125 per Common Unit. On May 13, 2011, we paid a cash distribution to unitholders for the first quarter of 2011 at the rate of $0.4175 per Common Unit. On August 12, 2011, we paid a cash distribution to unitholders for the second quarter of 2011 at the rate of $0.4225 per Common Unit. On November 14, 2011, we paid a cash distribution to unitholders for the third quarter of 2011 at the rate of $0.4350 per Common Unit. On February 14, 2012, we paid a cash distribution to unitholders for the fourth quarter of 2011 at the rate of $0.4500 per Common Unit.
In 2011, our oil and natural gas capital expenditures totaled approximately $75 million, compared with approximately $70 million in 2010. We spent approximately $34 million in Florida, $22 million in Michigan, Indiana and Kentucky, $10 million in Wyoming and $9 million in California. We drilled and completed 20 new wells, 38 recompletions and two workovers in Michigan. We drilled and completed nine new wells and four well optimization projects in Wyoming. We drilled and completed
six new wells and seven well optimization projects in California and Florida. Primarily as a result of our 2011 acquisitions and our capital spending, our 2011 production was 7,037 MMBoe, which was 5% higher than 2010.
During 2011, Quicksilver sold 15.7 million of our Common Units, representing its total ownership in the Partnership. As a result of Quicksilver selling 15.7 million of our Common Units together with normal trading activity by other unitholders, greater than 50% of our Common Units traded within a twelve month period and caused a technical termination of the Partnership for federal income tax purposes. This technical termination required the closing of our taxable year for all unitholders on November 30, 2011, and brought about two taxable periods for 2011: January 1, 2011 to November 30, 2011 and December 1, 2011 to December 31, 2011. We will be required to file two tax returns and, unless relief is granted by the IRS, issue two Schedules K-1 to each unitholder. See Note 12 to the consolidated financial statements in this report for further details about this technical termination that occurred in 2011.
In January 2012, we and BreitBurn Finance Corporation, and certain of our subsidiaries, as guarantors, issued $250 million in aggregate principal amount of 7.875% senior notes due 2022 at a price of 99.154%. We received net proceeds of approximately $242.3 million and used the proceeds to repay amounts outstanding under our credit facility.
In February 2012, we sold approximately 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $165.9 million, which we used to repay outstanding debt under our credit facility.
Outlook
In 2012, our crude oil and natural gas capital spending program, excluding acquisitions, is expected to be approximately $68 million, compared with approximately $75 million in 2011. We anticipate spending approximately 60% principally on oil projects in California and Florida and approximately 40% principally on oil projects in Michigan, Wyoming, Indiana and Kentucky. We anticipate 77% of our total capital spending will be focused on drilling and rate generating projects that are designed to increase or add to production or reserves. Without considering potential acquisitions, we expect our 2012 production to be approximately 8.1 MMBoe. Based on the continuing decline of natural gas prices, we will continue to evaluate our capital spending program throughout 2012.
Commodity hedging remains an important part of our strategy to reduce cash flow volatility. We use swaps, collars and options for managing risk relating to commodity prices. As of February 28, 2012, we had approximately 75% of our expected 2012 production hedged. For 2012, we had 7,516 Bbl/d of oil and 54,257 MMBtu/d of natural gas hedged at average prices of approximately $101.00 and $7.12, respectively. For 2013, we had 6,980 Bbl/d of oil and 56,000 MMBtu/d of natural gas hedged at average prices of approximately $92.05 and $5.96 respectively. For 2014, we had 6,000 Bbl/d of oil and 30,500 MMBtu/d of natural gas hedged at average prices of approximately $93.58 and $5.43, respectively. For 2015, we had 5,000 Bbl/d of oil and 30,500 MMBtu/d of natural gas hedged at average prices of approximately $96.41 and $5.55, respectively.
Consistent with our long-term business strategy, we intend to continue to actively pursue oil and natural gas acquisition opportunities in 2012.
Operational Focus
We use a variety of financial and operational measures to assess our performance. Among these measures are the following: volumes of oil and natural gas produced; reserve replacement; realized prices and operating and general and administrative expenses.
As of December 31, 2011, our total estimated proved reserves were 151.1 MMBoe, of which approximately 65% was natural gas and 35% was crude oil. As of December 31, 2010, our total estimated proved reserves were 118.9 MMBoe, of which approximately 65% was natural gas and 35% was crude oil.
We had estimated reserves revisions and purchase additions of 39.2 MMBoe in 2011, which were partially offset by 7.0 MMBoe of production. The increase in 2011 was primarily the result of 32.2 MMBoe of reserve acquisitions. Additionally, drilling, recompletions, workovers, addition of new drilling locations, economic factors and revised estimates of existing reserves contributed to the increase. The primary economic factor for the increase in estimated proved reserves relating to our oil producing properties was an increase in oil prices. The unweighted average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2011 were $95.97 per Bbl of oil for Michigan, California and Florida, $76.79 per Bbl of oil for Wyoming and $4.12 per MMBtu of gas, compared to $79.40 per Bbl of oil for Michigan, California and Florida, $65.36 per Bbl of oil for Wyoming and $4.38 per MMBtu of gas in 2010. The unweighted
average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2009 were $61.18 per Bbl of oil for Michigan, California and Florida, $51.29 per Bbl of oil for Wyoming and $3.87 per MMBtu of gas.
Of our total estimated proved reserves as of December 31, 2011, 49% were located in Michigan, 29% in Wyoming, 14% in California and 7% in Florida, with the remaining 1% in Indiana and Kentucky. On a net production basis, we operate approximately 87% of our production.
Our revenues and net income are sensitive to oil and natural gas prices. Our operating expenses are highly correlated to oil prices, and as oil prices rise and fall, our operating expenses will directionally rise and fall. Significant factors that will impact near-term commodity prices include global demand for oil and natural gas, political developments in oil producing countries, including, without limitation, the extent to which members of the OPEC and other oil exporting nations are able to manage oil supply through export quotas and variations in key North American natural gas and refined products supply and demand indicators.
In 2011, the NYMEX WTI spot price averaged approximately $95 per barrel, compared with approximately $79 per barrel a year earlier. In 2011, crude oil prices ranged from a monthly average low of $86 per barrel for September to a monthly average high of $110 per barrel for April. In 2010, prices ranged from a monthly average low of $74 per barrel for May to a monthly average high of $89 per barrel for December.
Prices for natural gas have historically fluctuated widely and in many markets are aligned both with supply and demand conditions in their respective regional markets and with the overall U.S. market. U.S. natural gas prices are also typically higher during the winter period when demand for heating is greatest. Since January 2009, monthly average natural gas spot prices at Henry Hub ranged from a low of $2.99 per MMBtu for September 2009 to a high of $5.83 per MMBtu for January 2010. During 2011, the natural gas spot price at Henry Hub ranged from a low of $2.84 per MMBtu to a high of $4.92 per MMBtu, with the monthly average ranging from a low of $3.17 per MMBtu for December to a high of $4.54 per MMBtu for June, and averaged approximately $4.00 per MMBtu for the year. During 2010, the natural gas spot price at Henry Hub ranged from a low of $3.18 per MMBtu to a high of $7.51 per MMBtu, and averaged approximately $4.37 per MMBtu. In January 2012, The natural gas spot price at Henry Hub averaged $2.67 per MMBtu in January 2012 and $2.48 per MMBtu for the first three weeks of February 2012.
Excluding the effect of derivatives, our realized average oil and NGL price for 2011 increased $19.21 per Boe to $89.92 per Boe as compared to $70.71 per Boe in 2010. Including the effects of derivative instruments but excluding the effects of hedge terminations, our realized average oil and NGL price increased $5.49 per Boe to $79.80 per Boe as compared to $74.31 per Boe in 2010, primarily due to the increase in crude oil prices. Our realized natural gas price for 2011 decreased $0.39 per Mcf to $4.18 per Mcf as compared to $4.57 per Mcf in 2010. Including the effects of derivative instruments, our realized natural gas price decreased $0.99 per Mcf to $6.58 per Mcf compared to $7.57 per Mcf in 2010, primarily due to the decrease in natural gas prices.
While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.
In evaluating our production operations, we frequently monitor and assess our operating and general and administrative expenses per Boe produced. These measures allow us to better evaluate our operating efficiency and are used in reviewing the economic feasibility of a potential acquisition or development project.
Operating expenses are the costs incurred in the operation of producing properties. Expenses for utilities, direct labor, water injection and disposal, production taxes and materials and supplies comprise the most significant portion of our operating expenses. A majority of our operating cost components are variable and increase or decrease along with our levels of production. For example, we incur power costs in connection with various production related activities such as pumping to recover oil and gas, separation and treatment of water produced in connection with our oil and gas production, and re-injection of water produced into the oil producing formation to maintain reservoir pressure. Although these costs typically vary with production volumes, they are driven not only by volumes of oil and gas produced but also volumes of water produced. Consequently, fields that have a high percentage of water production relative to oil and gas production, also known as a high water cut, will experience higher levels of power costs for each Boe produced. Certain items, however, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed. Our operating expenses are highly correlated to oil prices and
we experience upward or downward pressure on material and service costs depending on how oil prices change. These costs include specific expenditures such as lease fuel, electricity, drilling services and severance and property taxes. Lease operating expenses, including processing fees, were $18.64 per Boe in 2011 and $17.68 per Boe in 2010. The increase in per Boe lease operating expenses was primarily due to an increase in crude oil prices, higher Florida production costs related to new wells as well as higher well services, compression repairs and maintenance.
Production taxes vary by state. All states in which we operate impose ad valorem taxes on our oil and gas properties. Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Currently, Wyoming, Michigan, Indiana, Kentucky and Florida impose severance taxes on oil and gas producers at rates ranging from 1% to 8% of the value of the gross product extracted. Wyoming wells that reside on Indian or federal land are subject to an additional tax of 8.5%. California does not currently impose a severance tax; rather it imposes an ad valorem tax based in large part on the value of the mineral interests in place. See Part I-Item 1A "-Risk Factors" - "Risks Related to Our Business - We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations" in this report.
General and administrative expenses ("G&A"), excluding unit based compensation, were $4.45 per Boe in 2011 and $3.65 per Boe in 2010. The increase in per Boe G&A, excluding unit based compensation, was primarily due to acquisition and integration related costs and an increase in employee related expenses due to new hires.
BreitBurn Management
BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management also operates the assets of PCEC, our Predecessor. In 2008, BreitBurn Management entered into a five year Administrative Services Agreement to manage our Predecessor's properties. In 2008, we also entered into an Omnibus Agreement with our Predecessor detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of PCEC assets.
In addition to a monthly fee for indirect expenses, BreitBurn Management charges PCEC for all direct expenses including incentive plan costs and direct payroll and administrative costs related to PCEC properties and operations. The monthly fee for indirect expenses is contractually based on an annual projection of anticipated time spent by each employee who provides services to both us and PCEC during the ensuing year and is subject to renegotiation annually by the parties during the term of the agreement. See Note 6 to the consolidated financial statements in this report for a discussion of the process for determining the monthly fee.
The monthly fee in effect for 2011, 2010 and 2009 was determined to be $481,000, $456,000 and $500,000, respectively. In 2012, we expect the monthly fee for indirect costs to be approximately $571,000. The increase in the monthly fee for indirect expenses in 2012 primarily reflects additional anticipated services related to PCEC oil field development programs.
On January 6, 2012, Pacific Coast Oil Trust (the "Trust"), which was formed by PCEC, filed a registration statement on Form S-1 with the SEC in connection with an initial public offering (the "Trust Offering") by the Trust. Immediately prior to the closing of the Trust Offering, PCEC intends to convey net profits interests in its oil and natural gas production from certain of its properties to the Trust in exchange for Trust units. PCEC's assets consist primarily of producing and non-producing crude oil reserves located in Santa Barbara, Los Angeles and Orange Counties in California, including certain interests in the East Coyote and Sawtelle Fields. PCEC operates the Sawtelle and East Coyote Fields for the benefit of itself and the Partnership. The Partnership currently owns the non-operated interests in the East Coyote and Sawtelle Fields and pays an operating fee to PCEC. The annual operating fee in 2011 was $0.9 million. PCEC currently holds an average working interest of approximately 5.0% in the East Coyote and Sawtelle Fields. PCEC holds a reversionary interest in both of these fields, and its average working interest will increase to approximately 37.6% once certain payment milestones are achieved, which is currently expected to occur in the second quarter of 2012. The Partnership has no direct or indirect ownership interest in PCEC or the Trust.
The expected 2012 monthly fee charged by BMC to PCEC for indirect costs of $571,000 could change in connection with the Trust Offering. For more information on potential conflicts between us and PCEC, see Part I-Item 1A "-Risk Factors"- "Risks Related to Our Structure - Certain of the directors and officers of our General Partner, including our Chief Executive Officer, our President and other members of our senior management, own interests in PCEC, which is managed by our subsidiary, BreitBurn Management. Conflicts of interest may arise between PCEC, on the one hand, and us and our unitholders, on the other hand. Our partnership agreement limits the remedies available to you in the event you have a claim relating to
conflicts of interest."
See Note 6 to the consolidated financial statements in this report for more information regarding our relationship with BreitBurn Management and PCEC.
Results of Operations
The table below summarizes certain of the results of operations and period-to-period comparisons attributable to our operations for the periods indicated. These results are presented for illustrative purposes only and are not indicative of our future results. The data reflect our results as they are presented in our consolidated financial statements.
Comparison of Results of Operations for the Years Ended December 31, 2011, 2010 and 2009
The variances in our results of operations were due to the following components:
Production
For the year ended December 31, 2011 compared to the year ended December 31, 2010, production volumes increased by 338 MBoe, or 5%, primarily due to 368 MBoe from our southwestern Wyoming properties acquired on October 6, 2011, 88 MBoe from our eastern Wyoming properties acquired on July 28, 2011 and 41 MBoe higher Florida production from new wells partially offset by 129 MBoe lower Michigan natural gas production due to natural field declines. In 2011, natural gas, crude oil and natural gas liquids accounted for 54%, 44% and 2% of our production, respectively.
For the year ended December 31, 2010 compared to the year ended December 31, 2009, production volumes increased by 182 MBoe, or 3%, primarily due to 118 MBoe higher Florida production from the new Raccoon Point well, 100 MBoe higher Eastern region production from the capital work program and 13 MBoe higher California crude oil production, partially offset by the sale of the Lazy JL Field effective July 1, 2009, which produced 44 MBoe in 2009. In 2010, natural gas, crude oil and natural gas liquids accounted for 53%, 45% and 2% of our production, respectively.
Revenues
Total revenues increased by $125.0 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. Realized losses from commodity derivative instruments were $16.1 million in 2011 compared to realized gains of $74.8 million in 2010. Unrealized gains from commodity derivative instruments for the year ended December 31, 2011 were $97.7 million primarily reflecting a decrease in crude oil and natural gas futures prices during 2011. The effect of $36.8 million net loss on hedge contracts terminated in the fourth quarter of 2011 is reflected in realized and unrealized gains and losses on commodity derivative instruments for the year ended December 31, 2011. Unrealized losses from commodity derivative instruments for the year ended December 31, 2010 were $39.7 million primarily reflecting an increase in crude oil futures prices partially offset by a decrease in natural gas futures prices during 2010. For 2011 compared to 2010, higher commodity prices increased total sales revenues by approximately $56 million and higher sales volumes increased total sales revenues by approximately $21 million.
Total revenues increased by $150.5 million for the year ended December 31, 2010 compared to the year ended December 31, 2009. Realized gains from commodity derivative instruments were $74.8 million in 2010 compared to realized gains of $167.7 million in 2009. Unrealized losses from commodity derivative instruments for the year ended December 31, 2010 were $39.7 million reflecting an increase in crude oil futures prices partially offset by a decrease in natural gas futures prices during 2010. Unrealized losses from commodity derivative instruments for the year ended December 31, 2009 were $219.1 million reflecting the increase in both crude oil and natural gas futures prices during 2009. The effect of net proceeds of $45.6 million in hedge contracts monetized in January 2009 and $25.0 million in June 2009 are reflected in realized and unrealized gains and losses on commodity derivative instruments for the year ended December 31, 2009. For 2010 compared to 2009, higher commodity prices increased total sales revenues by approximately $55.0 million and higher sales volumes increased total sales revenues by approximately $7.8 million.
Lease operating expenses
Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2011 totaled $131.2 million or $18.64 per Boe, which was 5% higher per Boe than 2010. The increase was primarily attributable to an increase in crude oil prices, higher Florida production costs related to new wells as well as higher well services, compression repairs and maintenance. For the year ended December 31, 2011, $13.6 million or $1.93 per Boe of regional management costs were included in lease operating expenses compared to $12.9 million or $1.93 per Boe for the year ended December 31, 2010. The increase in regional management costs was primarily due to an increase in our short-term incentive compensation expense.
Production and property taxes for the year ended December 31, 2011 totaled $26.6 million, or $3.78 per Boe, which was 23% higher per Boe than the year ended December 31, 2010. The per Boe increase in production and property taxes compared to 2010 was primarily due to higher commodity prices in 2011.
Pre-tax lease operating expenses, including processing fees, for the year ended December 31, 2010 totaled $118.5 million or $17.68 per Boe, which was 1% lower per Boe than 2009. The decrease was primarily due to higher production volumes during 2010 compared to 2009. For the year ended December 31, 2010, $12.9 million or $1.93 per Boe of regional management costs were included in lease operating expenses compared to $10.9 million or $1.68 per Boe for the year ended
December 31, 2009. The increase in regional management costs was primarily due to an increase in our short-term incentive compensation expense.
Production and property taxes for the year ended December 2010 totaled $20.5 million, or $3.06 per Boe, which was 3% higher per Boe than the year ended December 31, 2009. The per Boe increase in production and property taxes compared to 2009 was primarily due to higher commodity prices in 2010.
Transportation expenses
In Florida, our crude oil is transported from the field by trucks and pipelines and then transported by barge to the sales point. Transportation costs incurred in connection with such operations are reflected in operating costs on the consolidated statements of operations. Transportation expenses for the years ended December 31, 2011 and 2010 were $5.3 million and $4.1 million, respectively. The increase in transportation expenses was primarily due to higher Florida sales volumes in 2011 as compared to 2010.
Transportation expenses for the years ended December 31, 2010 and 2009 were $4.1 million and $3.8 million, respectively. The increase in transportation expenses was primarily due to higher Florida sales volumes in 2010 as compared to 2009.
Change in inventory
In Florida, our crude oil sales are a function of the number and size of crude oil shipments in each year and thus crude oil sales do not always coincide with volumes produced in a given year. Sales occur on average every six to eight weeks. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are credited to operating costs through the change in inventory account. Production expenses are charged to operating costs through the change in inventory account when they are sold. In 2011 the change in inventory account amounted to a charge of $2.0 million reflecting the higher amount of barrels sold than produced during the year, compared to credits of $0.8 million in 2010 and $3.3 million in 2009, reflecting the higher amount of barrels produced than sold during the periods.
Depletion, depreciation and amortization
Depletion, depreciation and amortization ("DD&A") expense totaled $107.5 million, or $15.28 per Boe, for the year ended December 31, 2011, which was in line with DD&A of $15.34 per Boe for the year ended December 31, 2010. Included in DD&A for the year ended December 31, 2011 are $0.6 million in impairments related to uneconomic proved properties in Michigan. Included in DD&A for the year ended December 31, 2010 are $6.3 million in impairments related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. Excluding the impact of impairments, DD&A per Boe for 2011 and 2010 was $15.18 and $14.40, respectively. The increase in DD&A excluding impairments was primarily due to higher DD&A rates reflecting lower natural gas reserves as a result of a decrease in natural gas prices, and investment additions related to new wells in Florida.
DD&A expense totaled $102.8 million, or $15.34 per Boe, for the year ended December 31, 2010, a decrease of approximately 6% per Boe from the year ended December 31, 2009. The decrease in DD&A compared to 2009 was primarily due to the effect that higher 2010 commodity prices had on DD&A rates. Included in DD&A for the year ended December 31, 2010 are impairments of approximately $6.3 million related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. Excluding the impact of the impairments for 2010, DD&A per Boe for 2010 was $14.40 or 12% lower than 2009.
General and administrative expenses
Our general and administrative ("G&A") expenses totaled $53.3 million and $44.9 million in 2011 and 2010, respectively. This included $22.0 million and $20.4 million, respectively, in unit-based compensation expense related to employee incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new equity awards granted in the first quarter of 2011. For 2011, G&A expenses, excluding unit-based compensation, were $31.3 million, which was $6.8 million higher than 2010. The increase was primarily due to acquisition and integration costs related to the Cabot and Greasewood Acquisitions, higher employee related costs and higher short-term incentive compensation expense.
G&A expenses totaled $44.9 million and $36.4 million in 2010 and 2009, respectively. This included $20.4 million and $12.7 million, respectively, in unit-based compensation expense related to employee incentive plans. The increase in non-cash unit-based compensation expense was primarily due to new equity awards granted in the first quarter of 2010. For 2010, G&A expenses, excluding unit-based compensation, were $24.5 million, which was $0.8 million higher than 2009. The increase was
primarily due to higher short-term incentive compensation expense.
Unreimbursed litigation costs
In 2010, we recorded $1.4 million for unreimbursed litigation costs and legal fees related to the Quicksilver lawsuit that we did not expect to get reimbursed from our insurance companies. In 2011, we reduced the previously recorded $1.4 million provision by $0.1 million in anticipation of an insurance recovery, which we received in January 2012.
(Gain) loss on sale of assets
There was no material gain or loss on sale of assets for the years ended December 31, 2011 and 2010. The loss on sale of assets of $6.0 million for the year ended December 31, 2009 primarily reflects the $5.5 million loss on sale of the Lazy JL Field in Texas, which was sold in July 2009.
Interest expense, net of amounts capitalized
Our interest expense totaled $39.2 million for the year ended December 31, 2011, net of $0.1 million of capitalized interest, an increase of $14.6 million from 2010. This increase in interest expense was primarily attributable to an additional $19.9 million in interest expense associated with our 2020 Senior Notes, partially offset by $4.8 million lower interest expense on our credit facility due to a lower credit facility debt balance and $0.7 million lower amortization of debt issuance costs.
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. See Part II-Item 7A
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. See "Cautionary Statement Regarding Forward-Looking Information" in Part I-Item 1 "-Business" in this report.
See Note 5 to the consolidated financial statements in this report for additional information related to our financial instruments, including summaries of our commodity and interest rate derivative contracts at December 31, 2011 and a discussion of credit and counterparty risk.
Commodity Price Risk
Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas to achieve more predictable cash flows. We use swaps, collars and options for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash f low and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected. Please see Part I-Item 1A -"Risk Factors" - "Risks Related to Our Business - Our derivative activities could result in financial losses or could reduce our income, which may adversely affect our ability to pay distributions to our unitholders. To the extent we have hedged a significant portion of our expected production and actual production is lower than expected or the costs of goods and services increase, our profitability would be adversely affected." The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts.
Our commodity derivative instruments provide for monthly settlement based on the differential between the agreement price and the actual IPE Brent crude oil price, NYMEX WTI crude oil price, NYMEX Henry Hub natural gas price or MichCon City-Gate natural gas price.
We do not currently designate any of our derivative instruments as hedges for financial accounting purposes. In order to qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. Hedge effectiveness must be measured, at minimum, on a quarterly basis. Hedge accounting must be discontinued prospectively when a hedge instrument is no longer considered to be highly effective. Many of our commodity derivative instruments would not qualify for hedge accounting due to the ineffectiveness created by variability in our price discounts or differentials.
Our Los Angeles Basin crude oil is generally medium gravity crude. Because of its proximity to the extensive Los Angeles refinery market, it trades at only a minor discount to NYMEX WTI. Historically, WTI oil prices and IPE Brent oil prices have fluctuated together, but recently WTI and IPE Brent oil prices have diverged. Management believes that IPE Brent pricing will better correlate with local California prices we receive in the future. In 2011, IPE Brent prices were higher than WTI, and our California production traded at a premium to WTI. Our Wyoming crude oil, while generally of similar quality to our Los Angeles Basin crude oil, trades at a significant discount to NYMEX WTI because of its distance from a major refining market and the fact that our central Wyoming production is priced relative to the Bow River benchmark for Canadian heavy sour crude oil and our eastern Wyoming production is priced relative to Flint Hills Resources Wyoming Sweet posting, both of which have historically traded at a significant discount to NYMEX WTI. Our Florida crude oil also traded at a significant discount to NYMEX WTI primarily because of its low gravity and other quality characteristics as well as its distance from a major refining market.
Our Michigan properties have favorable natural gas supply/demand characteristics as the state has been importing an increasing percentage of its natural gas. To the extent our production is not hedged, the supply/demand situation has allowed us to sell our natural gas production with little or no discount to industry MichCon City-Gate prices. Our Wyoming natural gas trades at a discount to Henry Hub due to its relative location and the regional supply/demand market balances.
During 2011, the average differentials per barrel to NYMEX WTI benchmark prices were a $13.88 premium for our California-based oil production, a $15.42 discount for our Wyoming-based oil production and a $14.46 discount for our Florida-based oil production, including approximately $7.50 in transportation costs. During 2011, the average differentials per Mcf to Henry Hub benchmark prices were a $0.27 premium for our Michigan-based natural gas production and a $0.01 discount for our Wyoming-based natural gas production.
During 2010, the average discounts we received for our crude oil production relative to NYMEX WTI benchmark prices per barrel were $0.25 for California-based production, $13.24 for Wyoming-based production, and $16.15 for Florida-based production, including approximately $7.50 in transportation costs. During 2010, the average premium we received for our natural gas production relative to Henry Hub benchmark prices per Mcf was $0.17 for our Michigan-based production.
During 2009, the average discounts we received for our crude oil production relative to NYMEX WTI benchmark prices per barrel were $0.53 and $8.08 for our California and Wyoming-based production, respectively, and $18.71 for our Florida-based production, including approximately $7.50 in transportation costs. During 2009, the average premium we received for our natural gas production relative to Henry Hub benchmark prices per Mcf was $0.21 for our Michigan-based production.
All derivative instruments are recorded on the balance sheet at fair value. Fair value is generally determined based on the difference between the fixed contract price and the underlying market price at the determination date, and/or confirmed by the counterparty. Changes in the fair value of our commodity derivatives were recorded in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations, as a gain of $97.7 million for 2011 and a loss of $39.7 million for 2010.
Interest Rate Risk
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. We currently do not designate any of our interest rate derivatives as hedges for financial accounting purposes. At December 31, 2011, long-term debt outstanding under our credit facility was $520.0 million. At December 31, 2011, our LIBOR based debt was $518.0 million and our prime based debt was $2.0 million. In order to mitigate our interest rate exposure, we have entered into various interest rate swaps to fix a portion of floating LIBOR based debt under our credit facility. For the year ended December 31, 2011, our weighted average debt balance was $252 million and, if interest rates on the variable interest portion of our LIBOR and prime based debt of $80 million increased or decreased by 1%, our annual interest cost would have increased or decreased by approximately $0.8 million.
Changes in Fair Value
The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2011 was a net asset of approximately $131.2 million. The fair value of our outstanding oil and gas commodity derivative instruments at December 31, 2010 was a net asset of approximately $33.5 million.
As of December 31, 2011, with a $10 per barrel increase in the price of oil, and a corresponding $1 per Mcf increase in natural gas, our net commodity derivative instrument asset at December 31, 2011 would have decreased by approximately $144 million. With a $10 per barrel decrease in the price of oil, and a corresponding $1 per Mcf decrease in natural gas, our net commodity derivative instrument asset at December 31, 2011 would have increased by approximately $150 million.
Price risk sensitivities were calculated by assuming across-the-board increases in price of $10 per barrel for oil and $1 per Mcf for natural gas regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of actual changes in prompt month prices equal to the assumptions, the fair value of our derivative portfolio would typically change by less than the amounts given due to lower volatility in out-month prices.
The fair value of our outstanding interest rate derivative instruments was a net liability of approximately $4.4 million at December 31, 2011 and $4.8 million at December 31, 2010. With a 1% increase in the LIBOR rate, our outstanding interest rate derivative instruments net liability at December 31, 2011 would have decreased by approximately $3 million. With a 1% decrease in the LIBOR rate to a minimum rate of zero, our net liability at December 31, 2011 would have increased by approximately $2 million.
Changes in derivative instruments since December 31, 2011
On February 9, 2012, we entered into IPE Brent crude oil fixed price swap contracts for 500 Bbl/d for 2015 at $98.50 per Bbl.
Item 8.
Item 8. Financial Statements and Supplementary Data.
The information required by this Item 8 is incorporated herein by reference from the consolidated financial statements beginning on page.
Item 9.
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our General Partner's principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our General Partner's principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our General Partner's principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2011 at the reasonable assurance level.
Management’s Report on Internal Control Over Financial Reporting
The information required by this Item is incorporated by reference from "Management’s Report on Internal Control Over Financial Reporting" located on page.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
There was no information required to be disclosed in a report on Form 8-K during the fourth quarter of 2011 that has not previously been reported.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
Information concerning our directors, executive officers and corporate governance required by this Item is incorporated by reference to the material appearing in our Proxy Statement for the 2012 Annual Meeting of Unitholders ("2012 Proxy Statement"). The 2012 Annual Meeting of Unitholders is to be held on June 21, 2012.
The Board has established an audit committee and determined which members are our "audit committee financial experts." Information concerning our audit committee required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
We have adopted a Code of Ethics for Chief Executive Officers and Senior Officers. It is available on our website at http://ir.breitburn.com/documentdisplay.cfm?DocumentID=804.
Directors and Executive Officers of BreitBurn GP, LLC
The following table sets forth certain information with respect to the members of the board of directors and the executive officers of our General Partner. Executive officers and directors will serve until their successors are duly appointed or elected.
* Independent Directors
In accordance with that certain Settlement Agreement dated April 5, 2010, by and among Quicksilver, the Partnership, BreitBurn GP and certain other parties named therein, Messrs. W. Yandell Rogers, III and Walker C. Friedman each submitted his resignation, effective December 5, 2011, as a member of the Board due to Quicksilver having disposed of 100% of its interest in the Partnership. On December 5, 2011, the Board elected Messrs. Halbert S. Washburn, our Chief Executive Officer, and Randall H. Breitenbach, our President, as members of the Board. Mr. Washburn was elected to a term that will expire at the annual meeting to be held in 2013, and Mr. Breitenbach was elected to a term that will expire at the annual meeting to be held in 2014. Upon the expiration of their respective terms, they may each be reelected for a three year term. Messrs. Washburn and Breitenbach, as management of the Company, will not serve as members of the two independent committees of the Board and will not receive additional compensation for their services as directors.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the directors and executive officers of our General Partner, and persons who own more than 10% of a registered class of our equity securities (collectively, "Insiders"), to file reports of beneficial ownership on Form 3 and reports of changes in beneficial ownership on Form 4 or Form 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us from the individuals required to file reports, we believe that each of our executive officers and directors has complied with the applicable reporting
requirements for transactions in our securities during the fiscal year ended December 31, 2011 except as follows: Messrs. Brown and Smith each reported late the acquisition of Common Units, as a result of automatic distribution reinvestments, on February 14, 2011.
Item 11.
Item 11. Executive Compensation.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table sets forth certain information with respect to our equity compensation plans as of December 31, 2011.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
Item 14.
Item 14. Principal Accounting Fees and Services.
Information required by this Item is incorporated by reference to the material appearing in our 2012 Proxy Statement.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules.
(a) (1) Financial Statements
See “Index to the Consolidated Financial Statements” set forth on Page.
(2) Financial Statement Schedules
All schedules are omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.
(3) Exhibits
*
Filed herewith.
**
Furnished herewith.
†
Management contract or compensatory plan or arrangement.
††
The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BREITBURN ENERGY PARTNERS L.P.
By:
BREITBURN GP, LLC,
its General Partner
Dated: February 29, 2012
By:
/s/ Halbert S. Washburn
Halbert S. Washburn
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
BREITBURN ENERGY PARTNERS L.P. AND SUBSIDIARIES
INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Internal Control Over Financial Reporting
The management of BreitBurn Energy Partners, L.P. (the "Partnership") is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. The term "internal control over financial reporting" is defined as a process designed by, or under the supervision of, the Partnership's principal executive and principal financial officers, or persons performing similar functions, and effected by the Partnership’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Partnership; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Partnership are being made only in accordance with authorizations of management and directors of the Partnership; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Partnership's assets that could have a material effect on the financial statements.
Internal control over financial reporting, no matter how well designed, has inherent limitations. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
As required by Rule 13a-15(c) under the Exchange Act, the Partnership’s management, with the participation of the General Partner’s principal executive officers and principal financial officer, assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2011. In making this assessment, the Partnership’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control Integrated Framework. Based on this assessment, the Partnership’s management, including the general partner’s principal executive officers and principal financial officer, concluded that, as of December 31, 2011, the Partnership’s internal control over financial reporting was effective based on those criteria.
Management excluded from its assessment of the effectiveness of the Partnership's internal control over financial reporting the properties acquired in the Cabot Acquisition (as further described in Note 4 to the consolidated financial statements) because they were acquired in October 2011. The Cabot Assets represented approximately 13% of the Partnership's total assets as of December 31, 2011 and revenue from the Cabot Assets represented approximately 2% of the Partnership's total revenue for the year ended December 31, 2011.
PricewaterhouseCoopers LLP, the independent registered public accounting firm who audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued a report on the Partnership’s internal control over financial reporting as of December 31, 2011, which appears on page.
/s/ Halbert S. Washburn
/s/ James G. Jackson
Halbert S. Washburn
James G. Jackson
Chief Executive Officer of BreitBurn GP, LLC
Chief Financial Officer of BreitBurn GP, LLC
Report of Independent Registered Public Accounting Firm
To the Board of Directors of BreitBurn GP, LLC and Unitholders of BreitBurn Energy Partners L.P.
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, partners' equity and cash flows present fairly, in all material respects, the financial position of BreitBurn Energy Partners L.P. and its subsidiaries (“the Partnership”) at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As described in Management's Report on Internal Control Over Financial Reporting, management has excluded the properties acquired in the Cabot Acquisition from its assessment of internal control over financial reporting as of December 31, 2011 because the assets were acquired by the Partnership in a purchase business combination during October 2011. We have also excluded the Cabot properties from our audit of internal control over financial reporting. The Cabot properties total assets and total revenues represent 13% and 2%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2011.
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Operations
The accompanying notes are an integral part of these consolidated financial statements.
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Cash Flows
(a) 2011, 2010 and 2009 include distributions on unissued units under incentive plans of $5.1 million, $4.0 million and $0.7 million, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
BreitBurn Energy Partners L.P. and Subsidiaries
Consolidated Statements of Partners' Equity
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
Note 1. Organization
We are a Delaware limited partnership formed on March 23, 2006. Our initial public offering was in October 2006. Pacific Coast Energy Company LP ("PCEC"), formerly BreitBurn Energy Company L.P., was our Predecessor.
Our general partner is BreitBurn GP, LLC, a Delaware limited liability company (the "General Partner"), also formed on March 23, 2006. The board of directors of our General Partner has sole responsibility for conducting our business and managing our operations. We conduct our operations through a wholly owned subsidiary, BreitBurn Operating L.P, ("BOLP") and BOLP’s general partner BreitBurn Operating GP, LLC ("BOGP"). We own all of the ownership interests in BOLP and BOGP.
Our wholly owned subsidiary, BreitBurn Management, manages our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. See Note 6 for information regarding our relationship with BreitBurn Management. Our wholly owned subsidiary, BreitBurn Finance Corporation, was incorporated on June 1, 2009 under the laws of the State of Delaware. BreitBurn Finance Corporation has no assets or liabilities. Its activities are limited to co-issuing debt securities and engaging in other activities incidental thereto. Our wholly owned subsidiary, BreitBurn Collingwood Utica LLC ("Utica") holds certain non-producing oil and gas zones in the Collingwood-Utica shale play in Michigan and is classified as an unrestricted subsidiary under our credit facility.
During 2011, Quicksilver Resources Inc. ("Quicksilver"), a holder of 15.7 million of our limited partnership units ("Common Units") as of December 31, 2010, sold 0.1 million of our Common Units at an average price to the public of $21.88 per Common Unit, 7.6 million Common Units at a price to the public of $19.78 per Common Unit and 8.0 million Common Units at a price to the public of $16.52. These sales resulted in Quicksilver having disposed of 100% of its interest in the Partnership as of November 30, 2011. In 2011, The Baupost Group, L.L.C. sold 4.4 million of our Common Units, disposing of 100% of its interest in the Partnership.
As of December 31, 2011, public unitholders owned 98.85% of our Common Units and BreitBurn Energy Corporation owned 0.7 million Common Units, representing a 1.15% limited partner interest. We own 100% of the General Partner, BreitBurn Management, BOLP, BreitBurn Finance Corporation and Utica.
2. Summary of Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. Investments in affiliated companies with a 20% or greater ownership interest, and in which we do not have control, are accounted for on the equity basis. Investments in affiliated companies with less than a 20% ownership interest, and in which we do not have control, are accounted for on the cost basis. Investments in which we own greater than 50% interest and in which we have control are consolidated. Investments in which we own less than a 50% interest but are deemed to have control, or where we have a variable interest in an entity in which we will absorb a majority of the entity’s expected losses or receive a majority of the entity’s expected residual returns or both, however, are consolidated. The effects of all intercompany transactions have been eliminated.
Basis of presentation
Our financial statements are prepared in conformity with U.S. generally accepted accounting principles. Certain items included in the prior year financial statements were reclassified to conform to the 2011 presentation.
In 2011, we began classifying all debt issuance costs as long-term assets rather than allocating a portion to prepaid expenses. As such, we have revised the classification of debt issuance costs as of December 31, 2010, which is reflected in the following table. The change was not material to the prior period.
Use of estimates
The 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 disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including fair value of derivative instruments, unit based compensation and oil and gas reserve quantities, which are the basis for the calculation of depletion, depreciation, amortization, asset retirement obligations and impairment of oil and gas properties.
Business segment information
We report in one segment because our oil and gas operating areas have similar economic characteristics. We acquire, exploit, develop and produce oil and natural gas in the United States. Corporate management administers all properties as a whole rather than as discrete operating segments. Operational data is tracked by area; however, financial performance is measured as a single enterprise and not on an area-by-area basis. Allocation of capital resources is employed on a project-by-project basis across our entire asset base to maximize profitability without regard to individual areas.
Revenue recognition
Revenues associated with sales of our crude oil and natural gas are recognized when title passes from us to our customer. Revenues from properties in which we have an interest with other partners are recognized on the basis of our working interest ("entitlement" method of accounting). We generally market most of our natural gas production from our operated properties and pay our partners for their working interest shares of natural gas production sold. As a result, we have no material natural gas producer imbalance positions.
Accounts receivable
Our accounts receivable are primarily from purchasers of crude oil and natural gas and counterparties to our financial instruments. Crude oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserve until substantially all collection efforts have been exhausted. At December 31, 2011 and 2010, we did not carry an allowance for doubtful accounts receivable.
The settlement costs related to the Quicksilver lawsuit and the associated legal expenses were $13.0 million and approximately $8.7 million, respectively, of which we collected approximately $10.0 million from our insurance companies during the year ended December 31, 2010. Of the costs incurred in connection with the lawsuit, $1.4 million was estimated to be not recoverable from the insurance companies and is reflected as an expense in unreimbursed litigation costs on the consolidated statements of operations for the year ended December 31, 2010. The receivable at December 31, 2010 was $10.3 million. In 2011, we reduced the previously recorded $1.4 million provision by $0.1 million in anticipation of the final
insurance recovery payment of $10.4 million, which we received in January 2012. At December 31, 2011, accounts receivable included $10.4 million due from our insurance companies related to the lawsuit.
Inventory
Oil inventories are carried at the lower of cost to produce or market price. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded as inventory.
Investments in equity affiliates
Income from equity affiliates is included as a component of operating income, as the operations of these affiliates are associated with the processing and transportation of our natural gas production.
Property, plant and equipment
Oil and gas properties
We follow the successful efforts method of accounting. Lease acquisition and development costs (tangible and intangible) incurred relating to proved oil and gas properties are capitalized. Delay and surface rentals are charged to expense as incurred. Dry hole costs incurred on exploratory wells are expensed. Dry hole costs associated with developing proved fields are capitalized. Geological and geophysical costs related to exploratory operations are expensed as incurred.
Upon sale or retirement of proved properties, the cost thereof and the accumulated depletion, depreciation and amortization ("DD&A") are removed from the accounts and any gain or loss is recognized in the statement of operations. Maintenance and repairs are charged to operating expenses. DD&A of proved oil and gas properties, including the estimated cost of future abandonment and restoration of well sites and associated facilities, are generally computed on a field-by-field basis where applicable and recognized using the units-of-production method net of any anticipated proceeds from equipment salvage and sale of surface rights. Other gathering and processing facilities are recorded at cost and are depreciated using straight line, generally over 20 years.
We capitalize interest costs to oil and gas properties on expenditures made in connection with drilling and completion of new oil and natural gas wells. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the units of production method. During 2011 and 2010, interest of $0.1 million and $0.3 million, respectively, was capitalized and included in our capital expenditures. We had no capitalized interest in 2009.
Non-oil and gas assets
Buildings and non-oil and gas assets are recorded at cost and depreciated using the straight-line method over their estimated useful lives, which range from three to 10 years.
Oil and natural gas reserve quantities
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion are made concurrently with changes to reserve estimates. We disclose reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with the Securities and Exchange Commission (the "SEC") guidelines. The independent engineering firms adhere to the SEC definitions when preparing their reserve reports.
Asset retirement obligations
We have significant obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The fair value of a liability for an asset retirement obligation ("ARO") is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (1) expected economic recoveries of crude oil and natural gas, (2) time to abandonment, (3) future inflation rates and (4) the risk free rate of interest adjusted for our credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.
Impairment of assets
Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written down to estimated fair value. A long-lived asset is tested for impairment periodically and when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. For purposes of performing an impairment test, the undiscounted future cash flows are based on total proved and risk-adjusted probable and possible reserves, and are forecast using five-year NYMEX forward strip prices at the end of the period and escalated along with expenses and capital starting year six and thereafter at 2.5% per year. For impairment charges, the associated property’s expected future net cash flows are discounted using a rate of approximately 10%. Reserves are calculated based upon reports from third-party engineers adjusted for acquisitions or other changes occurring during the year as determined to be appropriate in the good faith judgment of management. Unproved properties are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred.
We assess our long-lived assets for impairment generally on a field-by-field basis where applicable. See Note 9 for a discussion of our impairments and price related depletion and depreciation adjustments.
Debt issuance costs
The costs incurred to obtain financing have been capitalized. Debt issuance costs are amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the "effective interest" method of amortization. Amortization of debt issuance costs for the year ended December 31, 2010 included a $1.5 million write-off of debt issuance costs as a result of the reduced borrowing base under our credit facility.
Equity-based compensation
BreitBurn Management has various forms of equity-based compensation outstanding under employee compensation plans that are described more fully in Note 17. Awards classified as equity are valued on the grant date and are recognized as compensation expense over the vesting period. We recognize equity-based compensation costs on a straight line basis over the annual vesting periods. Awards classified as liabilities are revalued at each reporting period and changes in the fair value of the options are recognized as compensation expense over the vesting schedules of the awards.
Fair market value of financial instruments
The carrying amount of our cash, accounts receivable, accounts payable, related party receivables and payables, and accrued expenses approximate their respective fair value due to the relatively short term of the related instruments. The carrying amount of long-term debt under our credit facility approximates fair value; however, changes in the credit markets may impact our ability to enter into future credit facilities at similar terms. See Note 10 for the fair value of our Senior Notes.
Accounting for business combinations
We account for all business combinations using the acquisition method. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, equity or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is recognized as a gain at the time of acquisition. All purchase price allocations are finalized within one year from the acquisition date. We have not recognized any goodwill from any business combinations.
Concentration of credit risk
We maintain our cash accounts primarily with a single bank and invest cash in money market accounts, which we believe to have minimal risk. At times, such balances may be in excess of the Federal Insurance Corporation insurance limit. As operator of jointly owned oil and gas properties, we sell oil and gas production to U.S. oil and gas purchasers and pay vendors on behalf of joint owners for oil and gas services. We periodically monitor our major purchasers’ credit ratings. We enter into commodity and interest rate derivative instruments. Our derivative counterparties are all lenders under our credit facility and
we periodically monitor their credit ratings.
Derivatives
Financial Accounting Standards Board ("FASB") Accounting Standards establish accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. These standards require recognition of all derivative instruments as assets or liabilities on our balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is designated as a hedge and if so, the type of hedge. We currently do not designate any of our derivatives as hedges for financial accounting purposes. Gains and losses on derivative instruments not designated as hedges are currently included in earnings. The resulting cash flows are reported as cash from operating activities.
Fair value measurement is based upon a hypothetical transaction to sell an asset or transfer a liability at the measurement date. The objective of fair value measurement is to determine the price that would be received in selling the asset or transferring the liability in an orderly transaction between market participants at the measurement date. If there is an active market for the asset or liability, the fair value measurement shall represent the price in that market whether the price is directly observable or otherwise obtained using a valuation technique.
Income taxes
Our subsidiaries are mostly partnerships or limited liability companies treated as partnerships for federal tax purposes with essentially all taxable income or loss being passed through to the members. As such, no federal income tax for these entities has been provided.
We have three wholly owned subsidiaries which are subject to corporate income taxes. Deferred income taxes are recorded under the asset and liability method. Where material, deferred income tax assets and liabilities are computed for differences between the financial statement and income tax bases of assets and liabilities that will result in taxable or deductible amounts in the future. Such deferred income tax asset and liability computations are based on enacted tax laws and rates applicable to periods in which the differences are expected to affect taxable income. Income tax expense is the tax payable or refundable for the period plus or minus the change during the period in deferred income tax assets and liabilities.
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. This accounting standard also provides guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial-statement comparability among different companies.
We performed evaluations as of December 31, 2011, 2010 and 2009 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.
Net Income or loss per unit
FASB Accounting Standards require use of the "two-class" method of computing earnings per unit for all periods presented. The "two-class" method is an earnings allocation formula that determines earnings per unit for each class of Common Unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable dividend rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested restricted phantom units ("RPUs") and convertible phantom units ("CPUs") participate in dividends on an equal basis with Common Units; therefore, there is no difference in undistributed earnings allocated to each participating security. Accordingly, our calculation is prepared on a combined basis and is presented as net income (loss) per Common Unit. See Note 15 for our earnings per Common Unit calculation.
Environmental expenditures
We review, on an annual basis, our estimates of the cleanup costs of various sites. When it is probable that obligations have been incurred and where a reasonable estimate of the cost of compliance or remediation can be determined, the applicable amount is accrued. For other potential liabilities, the timing of accruals coincides with the related ongoing site assessments. We do not discount these liabilities. At December 31, 2011, we had a $1.9 million environmental liability accrued that included cost estimates related to the maintenance of ground water monitoring wells associated with certain former well sites in Michigan that are no longer producing. At December 31, 2010, we had a $2.1 million environmental liability accrued.
3. Accounting Standards
Effective January 1, 2010, we adopted guidance issued by the FASB in June 2009 related to the consolidation of variable interest entities with no impact on our financial position, results of operations or cash flows.
In January 2010, the FASB issued an Accounting Standards Update ("ASU") that required two additional fair value measurement disclosures and clarifies two existing fair value measurement disclosures. The new disclosures require details of significant transfers in and out of Level 1 and Level 2 measurements and the reasons for the transfers, and a gross presentation of activity within the Level 3 roll forward that presents separately, information about purchases, sales, issuances and settlements. The ASU clarified the existing disclosures with regard to the level of disaggregation of fair value measurements by class of assets and liabilities rather than major category where the reporting entities would need to apply judgment to determine the appropriate classes of other assets and liabilities. The second clarification related to disclosures of valuation techniques and inputs for recurring and non-recurring fair value measurements using significant other observable inputs and significant unobservable inputs for Level 2 and Level 3 measurements, respectively. We adopted the ASU effective for our financial statements issued for interim and annual periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements which we adopted effective for interim and annual periods beginning after December 15, 2010. The adoption of the ASU has not had an impact on our financial position, results of operations or cash flows.
In May 2011, the FASB issued an ASU to improve comparability between US GAAP and International Financial Reporting Standards ("IFRS") fair value measurement and disclosure requirements. This amendment changes the wording used to describe many of the requirements in US GAAP for measuring fair value and for disclosing information about fair value measurements, particularly for Level 3 fair value measurements. For many of the requirements, the FASB does not intend for the amendments to result in a change in the application of the fair value measurement and disclosure requirements. Some of the amendments clarify the FASB's intent about the application of existing fair value measurement requirements. Other amendments change a particular principle or requirement for measuring fair value or for disclosing information about fair value measurements. This ASU is effective for interim and annual periods beginning after December 15, 2011. This ASU requires prospective application. We do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.
In December 2011, the FASB issued an ASU which requires companies to disclose information about financial instruments that have been offset and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. Companies will be required to provide both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset. This update is effective for interim and annual periods beginning on or after January 1, 2013 and requires retrospective application. We do not expect the adoption of this ASU to have a material impact on our financial position, results of operations or cash flows.
4. Acquisitions and Dispositions
Greasewood Acquisition
On July 28, 2011, we completed the acquisition of crude oil properties in the Powder River Basin in eastern Wyoming (the "Greasewood Field") with an effective date of July 1, 2011 (the "Greasewood Acquisition"). We used borrowings under our credit facility to fund the Greasewood Acquisition. The Greasewood Field is 100% oil and produced approximately 605 Bbl/d net in fourth quarter of 2011. This transaction was accounted for using the acquisition method. The purchase price for the acquisition was approximately $57 million in cash, and was allocated to the assets acquired and liabilities assumed as follows:
The purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and gas reserves were prepared by management in consultation with independent engineers. We applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated
proved reserves, the future net revenues were discounted using a rate of approximately 10%. There were no estimated quantities of hydrocarbons other than proved reserves allocated in the purchase price. Acquisition related costs for the Greasewood Acquisition were $0.1 million and were reflected in general and administrative expenses on the consolidated statements of operations.
In 2011, we recorded $7.4 million in sales revenue and $1.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Greasewood Acquisition.
Cabot Acquisition
On October 6, 2011, we completed the acquisition of oil and gas properties from Cabot Oil & Gas Corporation ("Cabot") located primarily in the Evanston and Green River Basins in southwestern Wyoming (the "Cabot Acquisition"), with an effective date of September 1, 2011. We used borrowings under our credit facility to fund the Cabot Acquisition. The assets acquired also include limited acreage and non-operated oil and gas interests in Colorado and Utah. These properties are 95% natural gas. These properties produced approximately 26 MMcfe/d net in fourth quarter of 2011. This transaction was accounted for under the acquisition method of accounting.
The preliminary purchase price of $281 million was allocated to the assets acquired and liabilities assumed as follows:
The preliminary purchase price allocation is based on discounted cash flows, quoted market prices and estimates made by management, the most significant assumptions related to the estimated fair values assigned to oil and gas properties with proved reserves. To estimate the fair values of these properties, estimates of oil and gas reserves were prepared by management in consultation with independent engineers. We applied estimated future prices to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a rate of approximately 10%. There were no estimated quantities of hydrocarbons other than proved reserves allocated in the preliminary purchase price. We will finalize the purchase price allocation within one year of the acquisition date. Acquisition related costs for the Cabot Acquisition were $0.6 million and were recorded in general and administrative expenses on the consolidated statements of operations.
In 2011, we recorded $9.1 million in sales revenue and $3.9 million in lease operating expenses, including production and property taxes, from the properties acquired in the Cabot Acquisition.
The following unaudited pro forma financial information presents a summary of our combined statement of operations for the years ended December 31, 2011 and 2010, assuming the Cabot Acquisition had been completed on January 1, 2010, including adjustments to reflect the allocation of the preliminary purchase price to the acquired net assets. The pro forma financial information is not necessarily indicative of the results of operations if the acquisition had been effective January 1, 2010.
Dispositions
On July 17, 2009, we sold the Lazy JL Field located in the Permian Basin of West Texas to a private buyer for $23 million in cash. This transaction was effective July 1, 2009. The Lazy JL Field properties produced approximately 245 Boe per day during the first six months of 2009, of which 96% was crude oil. The net carrying value at the date of sale was $28.5 million, of which $28.7 million was reflected in net property, plant and equipment on the balance sheet and $0.2 million was reflected in asset retirement obligation on the balance sheet. We recognized a loss of $5.5 million in 2009 related to the sale of the field.
5. Financial Instruments and Fair Value Measurements
Our risk management programs are intended to reduce our exposure to commodity prices and interest rates and to assist with stabilizing cash flows.
Commodity Activities
Due to the historical volatility of crude oil and natural gas prices, we have entered into various derivative instruments to manage exposure to volatility in the market price of crude oil and natural gas to achieve more predictable cash flows. We use swaps, collars and options for managing risk relating to commodity prices. All contracts are settled with cash and do not require the delivery of physical volumes to satisfy settlement. While this strategy may result in us having lower revenues than we would otherwise have if we had not utilized these instruments in times of higher oil and natural gas prices, management believes that the resulting reduced volatility of prices and cash flow is beneficial. While our commodity price risk management program is intended to reduce our exposure to commodity prices and assist with stabilizing cash flow and distributions, to the extent we have hedged a significant portion of our expected production and the cost for goods and services increases, our margins would be adversely affected.
The derivative instruments we utilize are based on index prices that may and often do differ from the actual crude oil and natural gas prices realized in our operations. These variations often result in a lack of adequate correlation to enable these derivative instruments to qualify for cash flow hedges under FASB Accounting Standards. Accordingly, we do not attempt to account for our derivative instruments as cash flow hedges for financial accounting purposes and instead recognize changes in the fair value immediately in earnings.
We had the following oil contracts in place at December 31, 2011:
In the fourth quarter of 2011, in order to improve the effectiveness of our hedge portfolio, we terminated certain crude oil fixed price swaps at NYMEX WTI prices for a total termination cost of $36.8 million and entered into new crude oil fixed price swaps for the same volumes and periods at IPE Brent prices. These transactions are reflected in the summary of oil commodity derivatives table above.
We had the following natural gas contracts in place at December 31, 2011:
Interest Rate Activities
We are subject to interest rate risk associated with loans under our credit facility that bear interest based on floating rates. As of December 31, 2011, our total debt outstanding under our credit facility was $520 million. In order to mitigate our interest rate exposure, we had the following interest rate swaps, indexed to 1-month LIBOR, in place at December 31, 2011, to fix a portion of floating LIBOR-base debt under our credit facility:
We do not currently designate any of our interest rate derivatives as hedges for financial accounting purposes.
Fair Value of Financial Instruments
FASB Accounting Standards require disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedge items are accounted for, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The required disclosures are detailed below.
Fair value of derivative instruments not designated as hedging instruments:
(a) Represents counterparty netting under derivative netting agreements - these contracts are reflected net on the balance sheet.
Gains and losses on derivative instruments not designated as hedging instruments:
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Included in loss on interest rate swaps on the consolidated statements of operations.
In January 2009, we terminated a portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts with the same counterparty for the same volumes at market prices. We realized gains of $32.3 million from the termination of crude oil contracts and $13.3 million from the termination of natural gas contracts.
In June 2009, we terminated an additional portion of our 2011 and 2012 crude oil and natural gas derivative contracts and replaced them with new contracts for the same volumes at market prices. We realized gains of $6.1 million from the termination of crude oil contracts and $18.9 million from the termination of natural gas derivative contracts.
In the fourth quarter of 2011, we terminated certain crude oil fixed price swaps at NYMEX WTI prices and entered into new crude oil fixed price swaps for the same volumes and periods at IPE Brent prices. We realized losses of $36.8 million from the terminations.
FASB Accounting Standards define fair value, establish a framework for measuring fair value and establish required disclosures about fair value measurements. They also establish a fair value hierarchy that prioritizes the inputs to valuation techniques into three broad levels based upon how observable those inputs are. We use valuation techniques that maximize the use of observable inputs and obtain the majority of our inputs from published objective sources or third party market participants. We incorporate the impact of nonperformance risk, including credit risk, into our fair value measurements. The fair value hierarchy gives the highest priority of Level 1 to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority of Level 3 to unobservable inputs. We categorize our fair value financial instruments based upon the objectivity of the inputs and how observable those inputs are. The three levels of inputs are described further as follows:
Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities as of the reporting date. Level 2 - Inputs other than quoted prices that are included in Level 1. Level 2 includes financial instruments that are actively traded but are valued using models or other valuation methodologies. We consider the over the counter ("OTC") commodity and interest rate swaps in our portfolio to be Level 2. Level 3 - Inputs that are not directly observable for the asset or liability and are significant to the fair value of the asset or liability. Level 3 includes financial instruments that are not actively traded and have little or no observable data for input into industry standard models. Certain OTC derivatives that trade in less liquid markets or contain limited observable model inputs are currently included in Level 3. As of December 31, 2011 and 2010, our Level 3 derivative assets and liabilities consisted entirely of OTC commodity put and call options.
Financial assets and liabilities that are categorized in Level 3 may later be reclassified to the Level 2 category at the point we are able to obtain sufficient binding market data. We had no transfers in or out of Levels 1, 2 or 3 during the years ended December 31, 2011, 2010 and 2009. Our policy is to recognize transfers between levels as of the end of the period.
Our Treasury/Risk Management group calculates the fair value of our commodity and interest rate swaps and options. We compare these fair value amounts to the fair value amounts that we receive from the counterparties on a monthly basis. Any differences are resolved and any required changes are recorded prior to the issuance of our financial statements.
The model we utilize to calculate the fair value of our commodity derivative instruments is a standard option pricing model. Inputs to the option pricing models include fixed monthly commodity strike prices and volumes from each specific contract, commodity prices from commodity forward price curves, volatility and interest rate factors and time to expiry. Model inputs are obtained from our counterparties and third party data providers and are verified to published data where available (e.g., NYMEX). Additional inputs to our Level 3 derivatives include option volatility, forward commodity prices and risk-free interest rates for present value discounting. We use the standard swap contract valuation method to value our interest rate derivatives, and inputs include LIBOR forward interest rates, one-month LIBOR rates and risk-free interest rates for present value discounting.
Assumed credit risk adjustments, based on published credit ratings and credit default swap rates, are applied to our derivative instruments.
Our assessment of the significance of an input to its fair value measurement requires judgment and can affect the valuation of the assets and liabilities as well as the category within which they are classified. Financial assets and liabilities carried at fair value on a recurring basis are presented in the following table:
The following table sets forth a reconciliation of changes in fair value of our derivative instruments classified as Level 3:
(a) Included in gain (loss) on commodity derivative instruments, net on the consolidated statements of operations.
(b) Settlements reflect the monetization of oil collar contracts in June 2009.
Credit and Counterparty Risk
Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivatives and accounts receivable. Our derivatives expose us to credit risk from counterparties. As of December 31, 2011, our derivative counterparties were Barclays Bank PLC, Bank of Montreal, Citibank, N.A, Credit Suisse Energy LLC, Union Bank N.A, Wells Fargo Bank National Association, JP Morgan Chase Bank N.A., The Royal Bank of Scotland plc, The Bank of Nova Scotia, BNP Paribas, U.S Bank National Association and Toronto-Dominion Bank. Our counterparties are all lenders under our Amended and Restated Credit Agreement. Our credit agreement is secured by our crude oil, natural gas and NGL reserves, so we are not required to post any collateral, and we conversely do not receive collateral from our counterparties. On all transactions where we are exposed to counterparty risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis. We periodically obtain credit default swap information on our counterparties. Although we currently do not believe we have a specific counterparty risk with any party, our loss could be substantial if any of these parties were to fail to perform in accordance with the terms of the contract. This risk is managed by diversifying our derivatives portfolio. As of December 31, 2011, each of these financial institutions had an investment grade credit rating. As of December 31, 2011, our largest derivative asset balances were with JP Morgan Chase Bank N.A., Union Bank N.A and Wells Fargo Bank National Association which accounted for approximately 37%, 10% and 10% of our derivative asset balances, respectively. As of December 31, 2011, our largest derivative liability balances were with BNP Paribas, The Royal Bank of Scotland plc and Citibank, N.A. which accounted for approximately 34%, 31% and 22% of our derivative liability balances, respectively.
6. Related Party Transactions
BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management.
On August 26, 2008, members of our senior management, in their individual capacities, together with Metalmark Capital Partners ("Metalmark"), Greenhill Capital Partners ("Greenhill") and a third-party institutional investor, completed the acquisition of PCEC. This transaction included the acquisition of a 96.02% indirect interest in PCEC, previously owned by Provident Energy Trust ("Provident"), and the remaining indirect interests in PCEC, previously owned by Randall H. Breitenbach, Halbert S. Washburn and other members of our senior management. PCEC is a separate Delaware oil and gas partnership with operations in California, was a separate U.S. subsidiary of Provident and was our Predecessor.
In connection with the acquisition of Provident’s ownership in PCEC by members of senior management, Metalmark, Greenhill and a third party institutional investor, BreitBurn Management entered into the Second Amended and Restated Administrative Services Agreement (the "Administrative Services Agreement") to manage PCEC's properties for a term of five years. In addition to a monthly fee for indirect expenses, BreitBurn Management charges PCEC for all direct expenses including incentive plan costs and direct payroll and administrative costs related to PCEC properties and operations. The monthly fee is contractually based on an annual projection of anticipated time spent by each employee who provides services to both us and PCEC during the ensuing year and is subject to renegotiation annually by the parties during the term of the agreement. Beginning in 2009, each BreitBurn Management employee estimated his or her time allocation independently. These estimates were then reviewed and approved by each employee’s manager or supervisor. The results of this process were provided to both the audit committee of the board of directors of our General Partner (composed entirely of independent directors) (the "audit committee") and the board of representatives of PCEC’s parent (the "PCEC board"). The audit committee and the non-management members of the PCEC board agreed on the monthly fee as provided in the Administrative Services Agreement. The monthly fees for 2011, 2010 and 2009 were set at $481,000, $456,000 and $500,000, respectively.
In addition, we entered into an Omnibus Agreement with PCEC detailing rights with respect to business opportunities and providing us with a right of first offer with respect to the sale of assets by PCEC.
At December 31, 2011 and December 31, 2010, we had net current receivables of $2.8 million and $3.2 million, respectively, due from PCEC related to the Administrative Services Agreement and employee related costs and oil and gas sales made by PCEC on our behalf from certain properties. During 2011, the monthly charges to PCEC for indirect expenses totaled $5.8 million and charges for direct expenses including direct payroll and administrative costs totaled $9.0 million. During 2011, net oil and gas sales made by PCEC on our behalf were approximately $13.9 million. During 2010, the monthly charges to PCEC for indirect expenses totaled $5.4 million and charges for direct expenses including direct payroll and administrative costs totaled $6.2 million. During 2010, net oil and gas sales made by PCEC on our behalf were approximately $10.3 million. During 2009, the monthly charges to BEC for indirect expenses totaled $6.5 million and charges for direct expenses including direct payroll and administrative costs totaled $6.1 million. During 2009, net oil and gas sales made by BEC on our behalf were
approximately $7.9 million.
At December 31, 2011 and December 31, 2010, we had receivables of $1.4 million and $0.4 million due from certain of our other affiliates, primarily representing investments in natural gas processing facilities, for management fees due from them and operational expenses incurred on their behalf.
Quicksilver buys natural gas from us in Michigan. For the year ended December 31, 2011, total net gas sales to Quicksilver were approximately $3.9 million. For the year ended December 31, 2010, total net gas sales to Quicksilver were approximately $3.4 million and the related receivable as of December 31, 2010 was $0.7 million. As of December 31, 2011, Quicksilver was no longer a related party.
7. Inventory
In Florida, crude oil inventory was $4.7 million and $7.3 million at December 31, 2011and 2010, respectively. For the year ended December 31, 2011, we sold 862 MBbls of crude oil and produced 782 MBbls from our Florida operations. For the year ended December 31, 2010, we sold 689 MBbls of crude oil and produced 734 MBbls from our Florida operations. Crude oil sales are a function of the number and size of crude oil shipments in each quarter and thus crude oil sales do not always coincide with volumes produced in a given quarter. Crude oil inventory additions are at cost and represent our production costs. We match production expenses with crude oil sales. Production expenses associated with unsold crude oil inventory are recorded to inventory.
We carry inventory at the lower of cost or market. When using lower of cost or market to value inventory, market should not exceed the net realizable value or the estimated selling price less costs of completion and disposal. We assessed our crude oil inventory at December 31, 2011 and December 31, 2010 and determined that the carrying value of our inventory was below market value and, therefore, no write-down was necessary.
For our properties in Florida, there are a limited number of alternative methods of transportation for our production. Substantially all of our oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs, or involuntary curtailment of our oil production, which could have a negative impact on our future consolidated financial position, results of operations and cash flows.
8. Equity Investments
We had equity investments at December 31, 2011 and December 31, 2010 totaling $7.5 million and $7.7 million, respectively, which primarily represent investments in natural gas processing facilities. For the years ended December 31, 2011 and 2010, we recorded $0.7 million in each period in earnings from equity investments and $0.9 million and $1.2 million, respectively, in dividends. For the year ended December 31, 2009, we recorded less than $0.1 million in earnings from equity investments and $1.4 million in dividends. Earnings from equity investments are reported in other revenue, net on the consolidated statements of operations.
At December 31, 2011, our equity investments consisted primarily of a 24.5% limited partner interest and a 25.5% general partner interest in Wilderness Energy Services LP, with a combined carrying value of $6.4 million. The remaining $1.1 million consists of smaller interests in several other investments where we have significant influence.
9. Impairments and Price Related Depletion and Depreciation Adjustments
We assess our developed and undeveloped oil and gas properties and other long-lived assets for possible impairment periodically and whenever events or changes in circumstances indicate that the carrying value of the assets may not be recoverable. Such indicators include changes in business plans, changes in commodity prices and, for crude oil and natural gas properties, significant downward revisions of estimated proved reserve quantities. If the carrying value of an asset exceeds the future undiscounted cash flows expected from the asset, an impairment charge is recorded for the excess of carrying value of the asset over its estimated fair value.
Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles, and the outlook for market supply and demand conditions for crude oil and natural gas. We consider the inputs for our impairments calculations to be Level 3 inputs. The impairment reviews and calculations are based on assumptions that are consistent with our business plans.
During the year ended December 31, 2011, we recorded impairments of approximately $0.6 million related to uneconomic proved properties in Michigan primarily due to a decrease in natural gas prices. During the year ended December 31, 2010, we recorded impairments of approximately $6.3 million related to our Eastern region properties, including a $4.2 million write-down of uneconomic proved properties and a $2.1 million write-down of expired unproved lease properties. For the year ended December 31, 2009, we reviewed our long-lived oil and gas assets and did not record any material impairments or price related adjustments to depletion and depreciation expense.
An estimate as to the sensitivity to earnings for these periods if other assumptions had been used in impairment reviews and calculations is not practicable, given the number of assumptions involved in the estimates. That is, favorable changes to some assumptions might have avoided the need to impair any assets in these periods, whereas unfavorable changes might have caused an additional unknown number of other assets to become impaired.
10. Long-Term Debt
Senior Notes Due 2020
On October 6, 2010, we and BreitBurn Finance Corporation (the "Issuers"), and certain of our subsidiaries as guarantors (the "Guarantors"), issued $305 million in aggregate principal amount of 8.625% Senior Notes due 2020 (the "2020 Senior Notes"). The 2020 Senior Notes were sold pursuant to a private placement exemption from the Securities Act of 1933, as amended (the "Securities Act") to a group of initial purchasers" and then resold to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. In connection with the issuance of the 2020 Senior Notes, on January 19, 2011, the Issuers filed a registration statement on Form S-4 with the SEC with respect to an offer to exchange the 2020 Senior Notes for substantially identical notes that are registered under the Securities Act. On February 17, 2011, the exchange registration statement became effective and we commenced the exchange offer, which was completed on March 30, 2011.
We received net proceeds of approximately $291.2 million (after deducting estimated fees and offering expenses). We used $290 million of the net proceeds to repay amounts outstanding under our credit facility. In connection with the 2020 Senior Notes, we incurred financing fees and expenses of approximately $8.8 million, which will be amortized over the life of the 2020 Senior Notes. The 2020 Senior Notes were offered at a discount price of 98.358%, or $300 million. The $5 million discount will be amortized straight-line over the life of the 2020 Senior Notes.
As of December 31, 2011 and 2010, the 2020 Senior Notes had a carrying value of $300.6 million and $300.1 million, respectively, net of an unamortized discount of $4.4 million and $4.9 million, respectively. As of December 31, 2011 and 2010, the fair value of the 2020 Senior Notes was estimated to be $320 million and $307 million, respectively, based on prices quoted from third-party financial institutions.
Credit Facility
On November 1, 2007, in connection with the Quicksilver Acquisition, BOLP, as borrower, and we and our wholly owned subsidiaries, as guarantors, entered into a four year, amended and restated revolving credit facility with Wells Fargo Bank, N.A., Credit Suisse Securities (USA) LLC and a syndicate of banks (the "Amended and Restated Credit Agreement"). On May 7, 2010, BOLP, as borrower, and we and our wholly-owned subsidiaries, as guarantors, entered into the Second Amended and Restated Credit Agreement, a four-year, $1.5 billion revolving credit facility with Wells Fargo Bank, National Association, as Administrative Agent, Swing Line Lender and Issuing Lender, and a syndicate of banks (the "Second Amended and Restated Credit Agreement"). The Second Amended and Restated Credit Agreement set our borrowing base at $735 million and extended the maturity date to May 7, 2014.
On September 17, 2010, we entered into the First Amendment to the Second Amended and Restated Credit Agreement, which included a consent to the formation of a new wholly owned subsidiary, Utica, and its designation as an unrestricted subsidiary under our credit facility. Utica is not a guarantor of indebtedness under our credit facility. As a result of the issuance of the 2020 Senior Notes on October 6, 2010, our borrowing base was automatically reduced to $658.8 million.
On May 9, 2011, we entered into the Second Amendment to the Second Amended and Restated Credit Agreement (the "Second Amendment"), which increased our borrowing base to $735 million and extended the maturity date to May 9, 2016. The Second Amendment also revised certain covenants in the credit facility, which included: eliminating the interest coverage ratio and the "borrowing base availability" test (applied prior to making distributions to unitholders or making other restricted payments); increasing the maximum leverage coverage ratio to 4.00 to 1.00 from 3.75 to 1.00; increasing our ability to incur or
guaranty an additional $350 million of unsecured senior notes (subject to our borrowing base being reduced by 25% of the original stated principal amount of such new debt); and adjusting the pricing grid by decreasing the applicable margins (as defined in the Second Amended and Restated Credit Agreement) by 25 basis points.
On August 3, 2011, we entered into the Third Amendment (the "Third Amendment") to the Second Amended and Restated Credit Agreement, which permits us to hedge oil and gas volumes for properties for which we have entered into a purchase agreement prior to closing the transaction. The Third Amendment also provides that such hedges must be terminated in the event that the acquisition does not close within 90 days of the execution of such purchase agreement.
On October 5, 2011, in connection with the completion of the Cabot Acquisition, we entered into the Fourth Amendment (the "Fourth Amendment") to the Second Amended and Restated Credit Agreement. The Fourth Amendment provides for an increase in the volume of permitted gas imbalances under the Credit Agreement from 300 MMcf to 1,000 MMcf
On October 11, 2011, our semi-annual borrowing base redetermination resulted in our borrowing base being set at $850 million.
As of December 31, 2011 and December 31, 2010, we had $520.0 million and $228.0 million, respectively, in indebtedness outstanding under the credit facility. At December 31, 2011, the 1-month LIBOR interest rate plus an applicable spread was 2.550% on the 1-month LIBOR portion of $518.0 million and the prime rate plus an applicable spread was 4.500% on the prime debt portion of $2.0 million. The amounts reported on our consolidated balance sheets for long-term debt approximate fair value due to the variable nature of our interest rates.
Borrowings under the Second Amended and Restated Credit Agreement are secured by first-priority liens on and security interests in substantially all of our and certain of our subsidiaries’ assets, representing not less than 80% of the total value of our oil and gas properties.
The Second Amended and Restated Credit Agreement contains customary covenants, including restrictions on our ability to: incur additional indebtedness; make certain investments, loans or advances; make distributions to our unitholders or repurchase units (including the restriction on our ability to make distributions unless, after giving effect to such distribution, we remain in compliance with all terms and conditions of our credit facility); make dispositions or enter into sales and leasebacks; or enter into a merger or sale of our property or assets, including the sale or transfer of interests in our subsidiaries.
EBITDAX is not a defined GAAP measure. The Second Amended and Restated Credit Agreement defines EBITDAX as consolidated net income plus exploration expense, interest expense, income tax provision, depletion, depreciation and amortization, unrealized loss or gain on derivative instruments, non-cash charges, including non-cash unit based compensation expense, loss or gain on sale of assets (excluding gain or loss on monetization of derivative instruments), cumulative effect of changes in accounting principles, cash distributions received from our unrestricted entities (as defined in the Second Amended and Restated Credit Agreement) and BreitBurn Energy Partners I, L.P. ("BEPI") and excluding income from our unrestricted entities and BEPI. All calculations of EBITDAX, for any applicable period during which a permitted acquisition or disposition is consummated, are determined on a pro forma basis as if such acquisition or disposition was consummated on the first day of such applicable period.
The Second Amended and Restated Credit Agreement also permits us to terminate derivative contracts without obtaining the consent of the lenders in the facility, provided that the net effect of such termination plus the aggregate value of all dispositions of oil and gas properties made during such period, together, does not exceed 5% of the borrowing base, and the borrowing base will be automatically reduced by an amount equal to the net effect of the termination.
The events that constitute an Event of Default (as defined in the Second Amended and Restated Credit Agreement) include: payment defaults; misrepresentations; breaches of covenants; cross-default and cross-acceleration to certain other indebtedness; adverse judgments against us in excess of a specified amount; changes in management or control; loss of permits; certain insolvency events; and assertion of certain environmental claims.
Interest Expense
Our interest expense is detailed in the following table:
11. Condensed Consolidating Financial Statements
Given that certain, but not all, of our subsidiaries have issued full, unconditional and joint and several guarantees of our Senior Notes, in accordance with Rule 3-10(d) of Regulation S-X, the following presents condensed consolidating financial information as of December 31, 2011 and 2010, and for the years ended December 31, 2011, 2010 and 2009 on a parent/co-issuer, guarantor subsidiaries, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Such subsidiary guarantees may be released under certain circumstances including the sale of the subsidiary or its assets. All subsidiaries are reflected on an equity method basis. Eliminating entries presented are necessary to combine the parent/co-issuer, guarantor subsidiaries and non-guarantor subsidiaries. For purposes of the following tables, we and BreitBurn Finance Corporation are referred to as "Parent/Co-Issuer" and the "Guarantor Subsidiaries" are all of our subsidiaries other than BEPI and Utica (together the "Non-Guarantor Subsidiaries").
Condensed Consolidating Balance Sheets
Condensed Consolidating Balance Sheets
Condensed Consolidating Statements of Operations
Condensed Consolidating Statements of Operations
Condensed Consolidating Statements of Operations
Condensed Consolidating Statements of Cash Flows
Condensed Consolidating Statements of Cash Flows
Condensed Consolidating Statements of Cash Flows
12. Income Taxes
We, and all of our subsidiaries, with the exception of Phoenix Production Company ("Phoenix"), Alamitos Company, BreitBurn Management and BreitBurn Finance Corporation, are partnerships or limited liability companies treated as partnerships for federal and state income tax purposes. Essentially all of our taxable income or loss, which may differ considerably from the net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our partners. As such, we have not recorded any federal income tax expense for those pass-through entities.
The consolidated income tax expense (benefit) attributable to our tax-paying entities consisted of the following:
(a) Related to Phoenix Production Company, our wholly owned subsidiary.
(b) Primarily in Michigan, California and Texas.
The following is a reconciliation of federal income taxes at the statutory rates to federal income tax expense (benefit) for Phoenix:
At December 31, 2011 and 2010, net deferred federal income tax liabilities of $2.8 million and $2.1 million, respectively, were reported in our consolidated balance sheet for Phoenix. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting and the amount used for income tax purposes. Significant components of our net deferred tax liabilities are presented in the following table:
At December 31, 2011 and 2010, we had $0 and $0.5 million, respectively, of estimated unused operating loss carry forwards. We did not provide a valuation allowance against this deferred tax asset as taxable income offset our prior operating loss carry forwards.
On a consolidated basis, cash paid for federal and state income taxes totaled $0.3 million in 2011, $0.2 million in 2010 and $0.6 million in 2009.
FASB Accounting Standards clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements. A company can only recognize the tax position in the financial statements if the position is more-likely-than-not to be upheld on audit based only on the technical merits of the tax position. FASB Accounting Standards also provide guidance on thresholds, measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition that is intended to provide better financial statement comparability among different companies.
We performed evaluations as of December 31, 2011, 2010 and 2009 and concluded that there were no uncertain tax positions requiring recognition in our financial statements.
During 2011, Quicksilver sold its total interests of 15.7 million of our Common Units. The sales by Quicksilver, together with normal trading activity by other public unitholders, resulted in the sale or exchange of greater than 50% of our capital and profits interests within a 12-month period, which caused a technical termination of the Partnership for federal income tax purposes. This technical termination does not affect our financial statements nor does it affect our classification as a partnership for federal income tax purposes or otherwise impact the nature of our qualifying income. The technical termination will result in a deferral of depreciation deductions that would otherwise be allowable in computing the taxable income of our unit holders. Other tax adjustments allowable in computing the taxable income of unitholders for calendar year 2011 could also not be evenly distributed over the two tax periods.
The technical termination will result in the closing of our taxable year for all units holders as of November 30, 2011, with two taxable periods for 2011 - one from January 1, 2011 to November 30, 2011 and one from December 1, 2011 to December 31, 2011. As a result, we will be required to file two tax returns and issue two sets of schedule K-1s to each unitholder if relief is not granted by the IRS. The IRS has a technical termination relief program that allows publicly traded partnerships that have technically terminated to apply for relief and if such relief is granted, we will be able to provide only one schedule K-1 to unit holders for the year even though we must still file two separate period tax returns for the year (i.e., the two tax periods would be combined into one schedule K-1 for unit holders). Although we have applied to the IRS for this relief, there is no assurance that this relief will be granted.
13. Asset Retirement Obligation
Our asset retirement obligation is based on our net ownership in wells and facilities and our estimate of the costs to abandon and remediate those wells and facilities as well as our estimate of the future timing of the costs to be incurred. Payments to settle asset retirement obligations occur over the operating lives of the assets, estimated to be from less than one year to 50 years. We expect our cash settlements to be approximately $0.1 million, $0.1 million and $0.5 million for the years 2013, 2015 and 2016, respectively. Cash settlements for the years after 2016 are expected to be $81.7 million. Our estimated asset retirement obligation has been discounted at our credit adjusted risk free rate of 7% and adjusted for inflation using a rate of 2%. Our credit adjusted risk free rate is calculated based on our cost of borrowing adjusted for the effect of our credit standing and specific industry and business risk. Each year we review and, to the extent necessary, revise our asset retirement obligation estimates. During 2011 and 2010, we obtained new estimates to evaluate the cost of abandoning our properties. As a result, we increased our ARO estimates by $20.0 million and $9.6 million, respectively, to reflect recent increases in the costs incurred for plugging and abandonment activities primarily in California.
We consider the inputs to our asset retirement obligation valuation to be Level 3 as fair value is determined using discounted cash flow methodologies based on standardized inputs that are not readily observable in public markets.
Changes in the asset retirement obligation are presented in the following table:
(a) Attributable to increased cost estimates and revisions to reserve life.
14. Commitments and Contingencies
Lease Rental and Purchase Obligations
We have operating leases for office space and other property and equipment having initial or remaining non-cancelable lease terms in excess of one year. Our future minimum rental payments for operating leases at December 31, 2011 are presented below:
Net rental expense under non-cancelable operating leases was $3.4 million, $3.0 million and $2.6 million in 2011, 2010 and 2009, respectively.
At December 31, 2011, we had purchase obligations of $0.2 million and $0.2 million for 2012 and 2013, respectively.
Surety Bonds and Letters of Credit
In the normal course of business, we have performance obligations that are secured, in whole or in part, by surety bonds or letters of credit. These obligations primarily cover self-insurance and other programs where governmental organizations require such support. These surety bonds and letters of credit are issued by financial institutions and are required to be reimbursed by us if drawn upon. At December 31, 2011, we had $22.1 million in surety bonds and $0.3 million in letters of credit outstanding. At December 31, 2010, we had $15.1 million in surety bonds and $0.3 million in letters of credit outstanding.
Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statues to which we are subject.
15. Partners' Equity
At December 31, 2011 and 2010, we had 59.9 million and 54.0 million Common Units outstanding, respectively.
At December 31, 2011 and December 31, 2010, we had 9.7 million and 6.7 million, respectively, of units authorized for issuance under our long-term incentive compensation plans and there were 1.7 million and 2.6 million, respectively, of units outstanding under grants that are eligible to be paid in Common Units upon vesting.
During the years ended December 31, 2011, 2010 and 2009, approximately 1.0 million, 1.2 million and 0.1 million Common Units, respectively, were issued to employees and outside directors pursuant to vested grants under our First
Amended and Restated 2006 Long Term Incentive Plan ("LTIP").
On February 11, 2011, we sold approximately 4.9 million Common Units at a price to the public of $21.25 per Common Unit, resulting in proceeds net of underwriting discounts and expenses of $100 million.
Earnings per common unit
FASB Accounting Standards require use of the "two-class" method of computing earnings per unit for all periods presented. The "two-class" method is an earnings allocation formula that determines earnings per unit for each class of common unit and participating security as if all earnings for the period had been distributed. Unvested restricted unit awards that earn non-forfeitable distribution rights qualify as participating securities and, accordingly, are included in the basic computation. Our unvested RPUs and CPUs participate in distributions on an equal basis with Common Units. Accordingly, the presentation below is prepared on a combined basis and is presented as net income (loss) per common unit.
The following is a reconciliation of net income (loss) and weighted average units for calculating basic net income (loss) per common unit and diluted net income (loss) per common unit.
(a) Basic earnings per unit is based upon the weighted average number of Common Units outstanding plus the weighted average number of potentially issuable RPUs and CPUs. The year ended December 31, 2009 excludes 2,637 of potentially issuable weighted average RPUs and CPUs from participating securities, as we were in a loss position.
(b) The year ended December 31, 2009 excludes 102 weighted average anti-dilutive units from the calculation of the denominator for diluted earnings per common unit, as we were in a loss position.
Cash Distributions
The partnership agreement requires us to distribute all of our available cash quarterly. Available cash is cash on hand, including cash from borrowings, at the end of a quarter after the payment of expenses and the establishment of reserves for future capital expenditures and operational needs. We may fund a portion of capital expenditures with additional borrowings or issuances of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. The partnership agreement does not restrict our ability to borrow to pay distributions. The cash distribution policy reflects a basic judgment that unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.
Distributions are not cumulative. Consequently, if distributions on Common Units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future.
Distributions are paid within 45 days of the end of each fiscal quarter to holders of record on or about the first or second week of each such month. If the distribution date does not fall on a business day, the distribution will be made on the business day immediately preceding the indicated distribution date.
We do not have a legal obligation to pay distributions at any rate except as provided in the partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under the partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves the General Partner determines is necessary or appropriate to provide for the conduct of the business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters. The partnership agreement provides that any determination made by the General Partner in its capacity as general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity.
On February 11, 2011, we paid a cash distribution of approximately $22.4 million to our common unitholders of record as of the close of business on February 8, 2011. The distribution that was paid to unitholders was $0.4125 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.2 million to holders of outstanding RPUs and CPUs issued under our LTIP.
On May 13, 2011, we paid a cash distribution of approximately $24.6 million to our common unitholders of record as of the close of business on May 10, 2011. The distribution that was paid to unitholders was $0.4175 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.3 million to holders of outstanding RPUs and CPUs issued under our LTIP.
On August 12, 2011, we paid a cash distribution of approximately $24.9 million to our common unitholders of record as of the close of business on August 9, 2011. The distribution that was paid to unitholders was $0.4225 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.3 million to holders of outstanding RPUs and CPUs issued under our LTIP.
On November 14, 2011, we paid a cash distribution of approximately $25.7 million to our common unitholders of record as of the close of business on November 9, 2011. The distribution that was paid to unitholders was $0.4350 per Common Unit. We also paid cash equivalent to the distribution paid to our unitholders of $1.3 million to holders of outstanding RPUs and CPUs issued under our LTIP.
16. Noncontrolling interest
FASB Accounting Standards require that noncontrolling interests be classified as a component of equity and establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners.
We own the limited partner interest (99%) of BEPI. As such, we are fully consolidating the results of BEPI and are recognizing a noncontrolling interest representing the book value of the general partner’s interests. BEPI’s general partner interest is held by a wholly owned subsidiary of PCEC. At December 31, 2011 and December 31, 2010, the amount of this noncontrolling interest was $0.5 million and $0.5 million, respectively. For the years ended December 31, 2011 and 2010, we recorded net income attributable to the noncontrolling interest of $0.2 million and $0.2 million, respectively, and $0.2 million and $0.1 million, respectively, in dividends.
The general partner of BEPI holds a 35% reversionary interest under the existing limited partnership agreement applicable to the properties. This reversionary interest is expected to occur at a defined payout, which is estimated to occur in the second quarter of 2012 based on year-end price and cost projections.
17. Unit and Other Valuation-Based Compensation Plans
Effective on the initial public offering date of October 10, 2006, BreitBurn Management adopted the existing Long-Term Incentive Plan ("BreitBurn Management LTIP") and the Unit Appreciation Rights Plan ("UAR plan") of the predecessor as previously amended. The predecessor’s Executive Phantom Option Plan, Unit Appreciation Plan for Officers and Key Individuals (Founders Plan), and the Performance Trust Units awarded to the Chief Financial Officer during 2006 under the BreitBurn Management LTIP, were adopted by BreitBurn Management with amendments at the initial public offering date as
described in the subject plan discussions below.
In 2007, we entered into the First Amended and Restated 2006 Long-Term Incentive Plan ("LTIP").
We may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. We also have the right to alter or amend the long-term incentive plan or any part of the plan from time to time, including increasing the number of units that may be granted subject to the requirements of the exchange upon which the Common Units are listed at that time. However, no change in any outstanding grant may be made that would materially reduce the rights or benefits of the participant without the consent of the participant. The plan will expire when units are no longer available under the plan for grants or, if earlier, it is terminated by us.
Unit Based Compensation
FASB Accounting Standards establish requirements for charging compensation expenses based on fair value provisions. At December 31, 2011, the Restricted Phantom Units ("RPUs") and the Convertible Phantom Units ("CPUs") granted under our LTIP as well as the outstanding Directors RPUs discussed below were all classified as equity awards. These awards are being recognized as compensation expense on a straight line basis over the annual vesting periods as prescribed in the award agreements.
Prior year awards classified as liabilities were revalued at each reporting period using the Black-Scholes option pricing model and changes in the fair value of the options were recognized as compensation expense over the vesting schedules of the awards. These awards were settled in cash or had the option of being settled in cash or units at the choice of the holder, and were indexed to either our Common Units or to Provident Trust Units. The liability-classified option awards were distribution-protected awards through either an Adjustment Ratio as defined in the plan or the holders received cumulative distribution amounts upon vesting equal to the actual distribution amounts per Common Unit of the underlying notional Units.
We recognized $22.0 million, $20.4 million and $12.7 million of compensation expense related to our various plans for the years ended December 31, 2011, 2010 and 2009, respectively.
Restricted Phantom Units
RPUs are phantom equity awards that, to the extent vested, represent the right to receive actual partnership units upon specified payment events. Certain of our employees including our executives are eligible to receive RPU awards. We believe that RPUs properly incentivize holders of these awards to grow stable distributions for our common unitholders. RPUs generally vest in three equal annual installments on each anniversary of the vesting commencement date of the award. In addition, each RPU is granted in tandem with a distribution equivalent right that will remain outstanding from the grant of the RPU until the earlier to occur of its forfeiture or the payment of the underlying unit, and which entitles the grantee to receive payment of amounts equal to distributions paid to each holder of an actual partnership unit during such period. RPUs that do not vest for any reason are forfeited upon a grantee’s termination of employment.
The fair value of the RPUs is determined based on the fair market value of our units on the date of grant. RPU awards were granted to BreitBurn Management employees during the years ended December 31, 2011, 2010 and 2009 as shown in the table below. We recorded compensation expense of $16.9 million in 2011, $15.6 million in 2010 and $9.1 million in 2009 related to the amortization of outstanding RPUs over their related vesting periods. As of December 31, 2011, there was $17.4 million of total unrecognized compensation cost remaining for the unvested RPUs. This amount is expected to be recognized over the next two years. The total fair value of units that vested during the years ended December 31, 2011, 2010 and 2009 was $21.5 million, $16.9 million and $10.6 million, respectively.
The following table summarizes information about RPUs:
Convertible Phantom Units
In December 2007, seven executives, Halbert Washburn, Randall Breitenbach, Mark Pease, James Jackson, Gregory Brown, Thurmon Andress and Jackson Washburn, received 0.7 million units of CPUs at a grant price of $30.29 per Common Unit. Each of the awards has the vesting commencement date of January 1, 2008. CPUs are significantly tied to the amount of distributions we make to holders of our Common Units. As discussed further below, the number of CPUs ultimately awarded to each of these senior executives will be based upon the level of distributions to common unitholders achieved during the term of the CPUs. The CPU grants vest over a longer-term period of up to five years. Therefore, these grants will not be made on an annual basis. New grants could be made at the Board’s discretion at a future date after the present CPU grants have vested.
CPUs vest on the earliest to occur of (i) January 1, 2013, (ii) the date on which the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than or equal to $3.10 per Common Unit and (iii) upon the occurrence of the death or "disability" of the grantee or his or her termination without "cause" or for "good reason" (as defined in the holder’s employment agreement, if applicable). Unvested CPUs are forfeited in the event that the grantee ceases to remain in the service of BreitBurn Management. Prior to vesting, a holder of a CPU is entitled to receive payments equal to the amount of distributions made by us with respect to each of the Common Units multiplied by the number of Common Unit equivalents underlying the CPUs at the time of the distribution.
Under the original CPU Agreements, one Common Unit Equivalent (CUE) underlies each CPU at the time it was awarded to the grantee. However, the number of CUEs underlying the CPUs would increase at a compounded rate of 25% upon the achievement of each 5% compounded increase in the distributions paid by us to our common unitholders. Conversely, the number of CUEs underlying the CPUs would decrease at a compounded rate of 25% if the distributions paid by us to our common unitholders decreases at a compounded rate of 5%.
On October 29, 2009, the Compensation and Governance Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive. Originally under the CPU Agreements, the number of CUEs per CPU could be reduced over the five year life of the agreement to a minimum of zero, or be multiplied by a maximum of 4.77 times, based on our distribution levels. We suspended the payment of distributions in April 2009; therefore, holders of CPUs did not receive any distributions under the CPU Agreements as long as distributions were suspended. Under the original chart, if the CPUs were to vest currently - for instance in the case of the death or disability of a holder - zero units would vest to that holder. The Committee determined that the elimination of multipliers between zero and one best represented the original incentive and retention purpose of the CPU Agreements. With this modification to the CPU Agreements, the number of CUEs per CPU can no longer be less than one, regardless of Common Unit distribution levels.
On January 29, 2010, the Committee approved an amendment to each of the existing CPU Agreements entered into with each named executive. Under these agreements, each CPU entitles its holder to receive (i) a number of our Common Units at the time of vesting equal to the number of "common unit equivalents" ("CUEs") underlying the CPU at vesting, and (ii) current distributions on Common Units during the vesting period based on the number of CUEs underlying the CPU at the time of such distribution. The number of CUEs underlying each CPU is determined by reference to Common Unit distribution levels during the applicable vesting period, generally calculated based upon the aggregate amount of distributions made per Common Unit
for the four quarters preceding vesting. The amendment to the CPU agreements now limits the multiplier for 20% of the total number of CPUs and related CUEs granted in each award to "1."
On January 28, 2011, the Committee approved an amendment to each of the existing CPU Agreements entered into with each of named executives. This amendment to the CPU agreements now limits the multiplier for 40% of the total number of CPUs and related CUEs granted in each award to "1" instead of 20% in the prior amendment approved on January 29, 2010. As a result at vesting, CPUs for 40% of each award will convert to Common Units on a 1:1 basis, and with respect to that portion of the award, holders will lose the ability to earn additional Common Units based on increased distributions on Common Units. No other modification was made to the CPU Agreements under this amendment. The Committee determined that this cap on 40% of the CPUs was appropriate in light of the overall long-term incentive grants made to BreitBurn's executive officers in 2011. Because we were accruing compensation expense assuming a CUE multiplier of one, all of these amendments had no impact on compensation expense recorded. Compensation expense will be adjusted upon such time it deems probable that the CUE would increase due to increased distributions.
In the event that the CPUs vest on January 1, 2013 or if the aggregate amount of distributions paid to common unitholders for any four consecutive quarters during the term of the award is greater than $3.10 per Common Unit, the CPUs would convert into a number of Common Units equal to the number of Common Unit equivalents underlying the CPUs at such time (calculated based upon the aggregate amount of distributions made per Common Unit for the preceding four quarters subject to the 60% limitation put in place on January 28, 2011 as noted above). After January 1, 2011, under the terms of the CPU Agreements, all unvested CPUs would fully vest in the event of a termination without cause or good reason and upon death or disability.
We recorded compensation expense for CPUs of $4.1 million in 2011, $4.1 million in 2010 and $4.1 million in 2009. At December 31, 2011, there was $4.1 million of total unrecognized compensation cost related to remaining unvested CPUs. This amount is expected to be recognized in 2012.
Founders Plan Awards
Under the Founders Plan, participants received unit appreciation rights which provide cash compensation in relation to the appreciation in the value of a specified number of underlying notional phantom units. The value of the unit appreciation rights was determined on the basis of a valuation of the predecessor at the end of the fiscal period plus distributions during the period less the value of the predecessor at the beginning of the period. The base price and vesting terms were determined by BreitBurn Management at the time of the grant. Outstanding unit appreciation rights vest in the following manner: one-third vest three years after the grant date, one-third vest four years after the grant date and one-third vest five years after the grant date and are subject to specified service requirements.
Effective on the initial public offering date of October 10, 2006, all outstanding unit appreciation rights under the Founders Plan were adopted by BreitBurn Management and converted into three separate awards. The first and second awards became the obligations of our predecessor. The third award represented 0.3 million Partnership unit appreciation rights at a base price of $18.50 per unit with respect to the operations of the properties that were transferred to us for the period beginning on the initial public offering date of October 10, 2006. The award is liability-classified and is being charged to us as compensation expense over the remaining vesting schedule.
We recorded less than $0.1 million, less than $0.1 million and $(0.4) million for compensation expense (income) under the plan for the years ended December 31, 2011, December 31, 2010 and December 31, 2009, respectively.
The following table summarizes information about unit appreciation rights issued under the Founders Plan:
(a) In 2009, 102 units expired out of the money.
Partnership LTIP
Under our LTIP, Partnership-indexed restricted units (RTUs) and/or performance units (PTUs) were granted in 2007 to certain individuals other than the Chief Executive Officer and President. Partnership-indexed RTUs vest one third at the end of year one, one third at the end of year two and one third at the end of year three after grant. In general, cash payments equal to the value of the underlying notional units were made on the anniversary dates of the RTUs. Partnership-indexed PTUs vest three years from the end of third year after grant and are payable in cash or in Common Units of the Partnership if elected by the grantee at least 60 days prior to the vesting date. Partnership-indexed PTU payouts are further determined by a performance multiplier which can range from zero to 200% of the initial grant depending on the total return of the underlying notional units as compared to the returns of a selected peer group of companies. The multiplier is determined by comparing our total return to the returns of 49 companies in the Alerian MLP Index. Underlying notional units are established based on target salary LTIP threshold for each employee. The awarded notional units are adjusted cumulatively thereafter for distribution payments through the use of an adjustment ratio. The estimated fair value associated with the Partnership-indexed RTUs and PTUs is expensed in the statement of income over the vesting period.
Due to the suspension of our distribution in April 2009, the multiplier as calculated at the end of 2009 was below that required to generate a payout. As a result, all outstanding Partnership-indexed PTUs vested and expired January 1, 2010 and no payout was made. The remaining Partnership-indexed RTUs had a value of less than $0.1 million at December 31, 2009 which were paid in cash in January 2010.
We recognized a credit of $0.5 million of compensation expense for the year ended December 31, 2009.
Director Restricted Phantom Units
Effective with the initial public offering, we also made grants of Restricted Phantom Units in the Partnership to the non-employee directors of our General Partner. Each phantom unit is accompanied by a distribution equivalent unit right entitling the holder to an additional number of phantom units with a value equal to the amount of distributions paid on each of our Common Units until settlement. Upon vesting, the majority of the phantom units will be paid in Common Units, except for certain directors’ awards which will be settled in cash. The unit-settled awards are classified as equity and the cash-settled awards are classified as liabilities. The estimated fair value associated with these phantom units is expensed in the statement of income over the vesting period. The accumulated compensation expense for unit-settled awards is reported in equity, and for cash-settled grants, it is reflected as a liability on the consolidated balance sheet.
We recorded compensation expense for the director’s phantom units of approximately $1.0 million in 2011, $0.6 million in 2010 and $0.4 million in 2009. As of December 31, 2011, there was $0.6 million of total unrecognized compensation cost for the unvested Director Performance Units and such cost is expected to be recognized over the next two years.
The following table summarizes information about the Director Restricted Phantom Units:
* At grant date
18. Retirement Plan
BreitBurn Management operates our assets and performs other administrative services for us such as accounting, corporate development, finance, land administration, legal and engineering. All of our employees, including our executives, are employees of BreitBurn Management. BreitBurn Management has a defined contribution retirement plan, which covers substantially all of its employees on the first day of the month following the month of hire. The plan provides for BreitBurn Management to make regular contributions based on employee contributions as provided for in the plan agreement. Employees fully vest in BreitBurn Management’s contributions after five years of service. PCEC is charged for a portion of the matching contributions made by BreitBurn Management. For the years ended December 31, 2011, 2010 and 2009, we recognized expense related to matching contributions of $1.1 million, $1.0 million and $1.0 million, respectively.
19. Significant Customers
We sell oil, natural gas and natural gas liquids primarily to large domestic refiners. For the year ended December 31, 2011, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Plains Marketing & Transportation LLC, Marathon Oil Company and Sunoco Partners Marketing and Terminals L.P., which accounted for approximately 30%, 16%, 15% and 9% of net sales, respectively.
For the year ended December 31, 2010, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Marathon Oil Company, Plains Marketing & Transportation LLC and Sunoco Partners Marketing and Terminals L.P., which accounted for 30%, 16%, 12% and 10% of net sales, respectively.
For the year ended December 31, 2009, purchasers that accounted for 10% or more of our net sales were ConocoPhillips, Marathon Oil Company and Plains Marketing & Transportation LLC which accounted for 30%, 16% and 11% of net sales, respectively.
20. Subsequent Events
On January 10, 2012, we and BreitBurn Finance Corporation (the "Issuers"), and certain of our subsidiaries (the "Guarantors"), entered into a Purchase Agreement (the "Purchase Agreement") with the Initial Purchasers as defined therein (the "Initial Purchasers"), pursuant to which the Issuers agreed to sell $250 million in aggregate principal amount of the Issuers’ 7.875% Senior Notes due 2022 (the "2022 Senior Notes") to the Initial Purchasers in a private placement exempt from the registration requirements under the Securities Act. The 2022 Senior Notes have not been registered under the Securities Act or any state securities laws, and unless so registered, the securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The 2022 Senior Notes were resold by the Initial Purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act.
The 2022 Senior Notes were issued at a discount of 99.154%, or $247.9 million. The $2.1 million discount will be amortized over the life of the senior notes. In connection with the 2022 Senior Notes, our estimated financing fees and
expenses were approximately $5.6 million, which will be amortized over the life of the 2022 Senior Notes.
In connection with the issuance of the 2022 Senior Notes, we entered into a Registration Rights Agreement (the "Registration Rights Agreement") with the Guarantors and Initial Purchasers. Under the Registration Rights Agreement, the Issuers and the Guarantors agreed to cause to be filed with the SEC a registration statement with respect to an offer to exchange the senior notes for substantially identical notes that are registered under the Securities Act. The Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act. In addition, the Issuers and the Guarantors agreed to use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 400 days after January 13, 2012. If the offer to exchange is not completed on or before the 400th day following January 13, 2012, the annual interest rate borne by the notes will increase by 1% per annum until the offer to exchange is completed.
In January 2012, in connection with the issuance of the 2022 Senior Notes, our borrowing base was automatically reduced to $787.5 million in accordance with the terms of our credit facility. Our next semi-annual borrowing base redetermination is scheduled for April 2012.
On January 27, 2012, we announced a cash distribution to unitholders for the fourth quarter of 2011 at the rate of $0.4500 per Common Unit, which was paid on February 14, 2012 to the record holders of common units at the close of business on February 6, 2012.
In February 2012, we sold 9.2 million Common Units at a price to the public of $18.80, resulting in proceeds net of underwriting discounts and estimated offering expenses of $165.9 million.
On February 9, 2012, we entered into IPE Brent crude oil fixed price swap contracts for 500 Bbl/d for 2015 at $98.50 per Bbl.
Supplemental Information
A. Oil and Natural Gas Activities (Unaudited)
We calculate total estimated proved reserves and disclose our oil and natural gas activities in accordance with SEC guidelines. The definition of proved reserves incorporates a definition of “reasonable certainty" using the PRMS (Petroleum Resource Management System) standard of “high degree of confidence" for deterministic method estimates, or a 90% recovery probability for probabilistic methods used in estimating proved reserves. While SEC guidelines permit a company to establish undeveloped reserves as proved with appropriate degrees of reasonable certainty established absent actual production tests and without artificially limiting such reserves to spacing units adjacent to a producing well, we have elected not to add such undeveloped reserves as proved. For reserve reporting purposes we use unweighted average first-day-of-the-month pricing for the 12 calendar months. Costs associated with reserves are measured on the last day of the fiscal year.
Costs incurred
Our oil and natural gas activities are conducted in the United States. The following table summarizes our costs incurred for the past three years:
Capitalized costs
The following table presents the aggregate capitalized costs subject to depreciation, depletion and amortization relating to oil and gas activities, and the aggregate related accumulated allowance:
The average DD&A rate per equivalent unit of production for the year ended December 31, 2011, excluding non-oil and gas related DD&A, was $14.90 per Boe. The average DD&A rate per equivalent unit of production for the year ended December 31, 2010, excluding non-oil and gas related DD&A, was $14.95 per Boe.
Results of operations for oil and gas producing activities
The results of operations from oil and gas producing activities below exclude general and administrative expenses, interest expenses and interest income:
(a) Excludes (gain) loss on sale of assets of $(111), $14 and $5,965 for the years ended December 31, 2011,
2010 and 2009, respectively.
Supplemental reserve information
The following information summarizes our estimated proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the years ended December 31, 2011, 2010 and 2009. The following reserve information is based upon reports by Netherland, Sewell & Associates, Inc. ("NSAI") and Schlumberger Data & Consulting Services ("SLB"), independent petroleum engineering firms. NSAI provides reserve data for our California, Wyoming and Florida properties, and SLB provides reserve data for our Michigan, Kentucky and Indiana properties. The estimates are prepared in accordance with SEC regulations. We only utilize large, widely known, highly regarded, and reputable engineering consulting firms. Not only the firms, but the technical persons that sign and seal the reports are licensed and certify that they meet all professional requirements. Licensing requirements formally require mandatory continuing education and professional qualifications. They are independent petroleum engineers, geologists, geophysicists and petrophysicists.
Our reserve estimation process involves petroleum engineers and geoscientists. As part of this process, all reserves volumes are estimated using a forecast of production rates, current operating costs and projected capital expenditures. Reserves are based upon the unweighted average first-day-of-the-month prices for each year. Price differentials are then applied to adjust these prices to the expected realized field price. Specifics of each operating agreement are then used to estimate the net reserves. Production rate forecasts are derived by a number of methods, including decline curve analyses, volumetrics, material balance or computer simulation of the reservoir performance. Operating costs and capital costs are forecast using current costs combined with expectations of future costs for specific reservoirs. In many cases, activity-based cost models for a reservoir are utilized to project operating costs as production rates and the number of wells for production and injection vary.
The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve
reports is Mark L. Pease, the Executive Vice President and Chief Operating Officer of our General Partner. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining our General Partner, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation. Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with NSAI and SLB during the reserve estimation process to review properties, assumptions and relevant data.
Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report included in this report as exhibits 99.1 and 99.2 are Mr. J. Carter Henson, Jr. and Mr. Mike K. Norton. J. Carter Henson, Jr. has been practicing consulting petroleum engineering at NSAI since 1989. Carter is a Registered Professional Engineer in the State of Texas (License No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 22 years experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mike Norton has been practicing consulting petroleum geology at NSAI since 1989. Mike is a Certified Petroleum Geologist in the State of Texas (License No. 441) and has over 33 years of practical experience in petroleum geosciences, with over 28 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Within SLB. the technical person primarily responsible for preparing the reserves estimates set forth in the SLB reserves report including in this report as exhibit 99.3 is Mr. Charles M. Boyer II, who has been with Data & Consulting Services (DCS) Division of SLB since 1998. He attended The Pennsylvania State University and graduated with a Bachelor of Science Degree in Geological Sciences in 1976; he is a Certified Petroleum Geologist of the American Association of Petroleum Geologists (Reg. No. 5733); he is a Registered Professional Geologist in the Commonwealth of Pennsylvania (Reg. No. PG004509) and has in excess of 20 years' experience in the conduct of evaluation and engineering studies relating to oil and gas interests.
Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation methods and procedures consistently applied, are reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of the estimated proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted net future cash flows shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of oil and natural gas and increases in operating expenses have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and revenues, profitability and cash flow.
The following table sets forth certain data pertaining to our estimated proved and proved developed reserves for the years ended December 31, 2011, 2010 and 2009.
Revisions of Previous Estimates
In 2011, we had positive revisions of 7.0 MMBoe, primarily related to an increase in oil prices partially offset by a decrease in natural gas prices. Unweighted average first-day-of-the-month crude oil and natural gas prices used to determine our total estimated proved reserves as of December 31, 2011 were $95.97 per Bbl of oil for Michigan, California and Florida, $76.79 per Bbl of oil for Wyoming and $4.12 per MMBtu of gas, compared to $79.40 per Bbl of oil for Michigan, California and Florida, $65.36 per Bbl of oil for Wyoming and $4.38 per MMBtu of gas in 2010.
In 2010, we had positive revisions of 12.8 MMBoe, primarily related to an increase in both oil and natural gas prices. Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2009 were $61.18 per Bbl of oil for Michigan, California and Florida, $51.29 per Bbl of oil for Wyoming and $3.87 per MMBtu of gas.
In 2009, we had positive revisions of 15.3 MMBoe, primarily related to an increase in oil prices, partially offset by a decrease in natural gas prices. In accordance with SEC guidelines for 2008, oil and gas prices in effect as of December 31, 2008 were used as representative market prices for the reserve reports. The prices used in 2008 were $44.60 ($20.12 for Wyoming) per barrel of oil, and $5.71 per MMBtu of gas.
Conversion of Proved Undeveloped Reserves
During the years ended December 31, 2011, 2010 and 2009 , we incurred $15.4 million, $32.6 million and $5.8 million in capital expenditures, respectively, and drilled 28 wells, 16 wells and 11 wells, respectively, related to the conversion of proved undeveloped to proved developed reserves. During the years ended December 31, 2011, 2010 and 2009, we converted 1.0 MMBoe, 3.2 MMBoe and 0.6 MMBoe, respectively, from proved undeveloped to proved developed reserves. As of December 31, 2011, 2010 and 2009, we had no material proved undeveloped reserves that have remained undeveloped for more than five years. The increase in proved undeveloped reserves during the year ended December 31, 2011 was primarily due to the acquisition of 10.3 MMBoe and 1.9 MMBoe of proved undeveloped reserves in the Cabot Acquisition and the Greasewood Acquisition, respectively. The increase in proved undeveloped reserves during the year ended December 31, 2010 was not material.
Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows relating to our estimated proved crude oil and natural gas reserves as of December 31, 2011, 2010 and 2009 is presented below:
The standardized measure of discounted future net cash flows discounted at 10% from production of proved reserves was developed as follows:
1.
An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.
2.
In accordance with SEC guidelines, the reserve engineers' estimates of future net revenues from our estimated proved properties and the present value thereof are made using unweighted average first-day-of-the-month oil and gas sales prices and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various derivative instruments to fix or limit the prices relating to a portion of our oil and gas production. Derivative instruments in effect at December 31, 2011 and 2010 are discussed in Note 5. Such derivative instruments are not reflected in the reserve reports. Representative unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2011 were $95.97 per Bbl of oil for Michigan, California and Florida, $76.79 per Bbl of oil for Wyoming and $4.12 per MMBtu of gas, compared to $79.40 per Bbl of oil for Michigan, California and Florida, $65.36 per Bbl of oil for Wyoming and $4.38 per MMBtu of gas in 2010. Unweighted average first-day-of-the-month market prices for the reserve reports for the year ended December 31, 2009 were $61.18 per Bbl of oil for Michigan, California and Florida, $51.29 per Bbl of oil for Wyoming and $3.87 per MMBtu of gas.
3.
The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. Future net cash flows assume no future income tax expense as we are essentially a non-taxable entity except for four tax-paying corporations whose future income tax liabilities on a discounted basis are insignificant.
The principal sources of changes in the standardized measure of the future net cash flows for the years ended December 31, 2011, 2010 and 2009 are presented below:
B. Quarterly Financial Data (Unaudited)
(a) Due to changes in the number of weighted average common units outstanding that may occur each quarter, the earnings per unit amounts for certain quarters may not be additive.
EXHIBIT INDEX
*
Filed herewith.
**
Furnished herewith.
†
Management contract or compensatory plan or arrangement.
††
The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.