UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of report (Date of earliest event reported):  February 5, 2012

LONE PINE RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of incorporation)

403.292.8000

(Registrant’s telephone number, including area code)

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o    Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act  (17 CFR 240.14d-2(b))

o    Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 1.01.              Entry into a Material Definitive Agreement.

Third Amendment to Credit Agreement

On February 5, 2012, Lone Pine Resources Inc., as parent (“Lone Pine” or the “Company”), and Lone Pine Resources Canada Ltd., as borrower (“LPR Canada”), entered into the Third Amendment (the “Amendment”) to that certain Credit Agreement dated as of March 18, 2011, by and among Lone Pine, LPR Canada, JPMorgan Chase Bank, N.A., Toronto branch as Administrative Agent and the other agents and Lenders party thereto (as amended, the “Credit Agreement”), the operative provisions of which became effective on June 1, 2011. Pursuant to the provisions of the Amendment, the Credit Agreement was amended to, among other things, expand the definition of senior notes to include senior notes issued by the borrower or any of the parent’s or borrower’s restricted subsidiaries.  The operative provisions of the Amendment became effective on February 5, 2012.

As of January 27, 2012, Lone Pine had $339 million (CDN$339.0 million) in borrowings outstanding under its bank credit facility.  The borrowing base under the Credit Agreement is currently CDN$425 million.  If the private placement of senior notes due 2017 described below is completed as currently contemplated, (1) the borrowing base under the Credit Agreement will be automatically reduced from CDN$425 million to CDN$375 million and (2) as of January 27, 2011, after giving effect to the private placement of senior notes due 2017 and the application of the net proceeds therefrom, we would have had approximately $144 million (CDN$144 million) of borrowings outstanding under our bank credit facility and secured borrowing capacity of approximately $229 million (CDN$229.0 million) under our bank credit facility (after deducting CDN$1.6 million of outstanding letters of credit and giving effect to the automatic reduction in our borrowing base resulting from this offering).

The foregoing description of the Amendment is qualified in its entirety to the full text of the Amendment, a copy of which is attached to this Current Report on Form 8-K (this “Report”) as Exhibit 10.1 and is hereby incorporated by reference into this Item 1.01.

Item 2.02.                                          Results of Operations and Financial Condition.

On February 6, 2012, Lone Pine issued a press release announcing its 2011 year-end estimated proved reserves (as determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (the “SEC”)) and selected operational results for the quarter and year ended December 31, 2011.  A copy of the press release is furnished and attached to this Report as Exhibit 99.1 and is hereby incorporated by reference into this Item 2.02.

In accordance with General Instruction B.2 of Form 8-K, the information in this Item 2.02 of this Report, including Exhibit 99.1, shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall such information, including Exhibit 99.1, be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

Item 2.03.              Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant.

The information included, or incorporated by reference, in Item 1.01 of this Report is hereby incorporated by reference into this Item 2.03.

Item 7.01.              Regulation FD Disclosure.

Estimated Proved Reserves and Selected Operational Results

On February 6, 2012, Lone Pine issued a press release announcing its 2011 year-end estimated proved reserves (determined in accordance with SEC rules and regulations) and selected operational results for the quarter and year ended December 31, 2011.  A copy of the press release is furnished and attached to this Report as Exhibit 99.1 and is hereby incorporated by reference into this Item 7.01.

2

Private Placement of Senior Notes

On February 6, 2012, Lone Pine issued a press release announcing that it intends to commence a private placement of senior notes due 2017. A copy of the press release is furnished and attached to this Report as Exhibit 99.2 and is hereby incorporated by reference into this Item 7.01.

The information in this Report shall not constitute an offer to sell or the solicitation of an offer to buy, nor shall there be any sale of these securities in any state, province or other jurisdiction in which the offer, solicitation or sale would be unlawful prior to the registration or qualification under the securities laws of any such state, province or other jurisdiction.

In accordance with General Instruction B.2 of Form 8-K, the information in this Item 7.01 of this Report, including Exhibits 99.1 and 99.2, shall not be deemed “filed” for the purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that section, nor shall such information, including Exhibits 99.1 and 99.2, be deemed incorporated by reference in any filing under the Securities Act or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

Item 8.01.              Other Events.

In connection with the commencement of the private placement of senior notes due 2017, Lone Pine is providing the following updated disclosures with respect to its significant properties, reserves, drilling activities, oil and gas wells and commodity hedges.

Significant Properties

Lone Pine’s current asset base is composed of both light oil and natural gas opportunities. This diversified portfolio allows Lone Pine to focus on one commodity over another when disparity between commodity prices dictates. In 2011, Lone Pine was able to successfully increase its average liquids production weighting from 14% in the first quarter of 2011 to 27% in the fourth quarter of 2011 by focusing its capital investment on light oil. In 2012, Lone Pine plans to focus its capital budget on light oil by allocating approximately 80% of its total budget to light oil opportunities. Based on this focus, Lone Pine expects to increase its average liquids production weighting from 21% in 2011 to 35% in 2012 and to approximately 40% by the end of 2012. Lone Pine plans on continuing a diversified approach over the long term, with the majority of its capital allocated in the short term to assets with the highest rates of return.

Lone Pine has high working interests in its properties and currently operates approximately 82% of its production. Further, Lone Pine operated all of its 2011 drilling program and expects to operate substantially all of its planned 2012 drilling program. As the designated operator, Lone Pine believes it can maintain control over capital expenditures, operating costs and the pace of exploration and development. Lone Pine also has limited near-term lease expiries. As of December 31, 2011, approximately 85% of Lone Pine’s net acreage was held by leases whose terms extend beyond the next three years.

3

The following table presents summary data for each of Lone Pine’s significant properties as of December 31, 2011, unless otherwise indicated.

(1)                        Reserves and sales volumes are presented on a gas-equivalent basis using a conversion of 6 Mcf “equivalent” per barrel of oil or NGL. This conversion is based on energy equivalence and not price equivalence.  For 2011, the average of the first day of the month marker gas price was $4.15 per MMBtu for NYMEX Henry Hub ($3.81 per MMBtu at AECO), and the average of the first day of the month oil price was $96.13 per barrel for NYMEX West Texas Intermediate.  If a price equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 23 Mcf per barrel of oil or NGL rather than 6 Mcf per barrel of oil or NGL.

(2)                        For the three months ended December 31, 2011.

(3)                        On June 13, 2011, legislation was implemented in Quebec that prohibits oil and gas activities in the St. Lawrence River upstream of Anticosti Island and on the islands situated in that part of the river and revokes, without compensation, oil and gas rights previously issued for that area. Lone Pine held exploration licenses to 33,460 net acres under the St. Lawrence River that were revoked by this legislation and are considering available alternatives with respect to the government’s action. The revoked acreage consists entirely of undeveloped lands. No reserves are attributed to our Quebec properties.

Evi

As of December 31, 2011, Lone Pine had approximately 57,382 net acres in and near the Evi field, located in the Peace River Arch area of northern Alberta. This position offers Lone Pine a significant development opportunity for premium-priced light oil. Through December 31, 2011, Lone Pine drilled a total of 72 horizontal wells in the Evi area since Lone Pine entered the area in 2006. In 2011, Lone Pine drilled 47 gross (47 net) horizontal wells in the Evi area, and Lone Pine plans to drill up to 48 additional horizontal wells in the Evi area in 2012. Lone Pine’s working interest in all of the wells drilled in 2011 is 100%. For the 34 of the 2011 wells that have been brought on production, the average maximum recorded initial peak twenty-four hour production rate was approximately 329 Bbls per day. For the 30 of the 2011 wells that have been on production for at least 60 days, the 60-day average production rate was approximately 184 Bbls per day. For the 23 of the 2011 wells that have been on production for at least 90 days, the 90-day average production rate was approximately 179 Bbls per day. In the fourth quarter of 2011, Lone Pine had average daily net sales volumes of 3,605 Bbls per day from production in the Evi area. Lone Pine believes that it can ultimately enhance production rates and recoveries in the Evi area through further development drilling, including further downspacing of its acreage, completion optimization and secondary recovery techniques, such as waterflooding. In 2012, Lone Pine plans to focus its capital budget on light oil by allocating approximately 80% of its total capital budget, or approximately $165 million, to the Evi area.

4

Deep Basin Area

As of December 31, 2011, Lone Pine had approximately 157,779 net acres in the Deep Basin, including approximately 121,088 net acres in the Narraway/Ojay fields, located in Alberta and British Columbia, and approximately 12,853 net acres in the Wild River field, located in the southeast portion of the Deep Basin. In 2011, Lone Pine drilled and completed 6 gross (5.5 net) wells in the Narraway/Ojay fields, including 1 gross (1 net) horizontal well. In the fourth quarter of 2011, Lone Pine had average daily net sales volumes of 66 MMcfe per day from production in the Deep Basin. Lone Pine’s development of these assets is primarily focused on its Narraway/Ojay and Wild River fields. Geologically, these fields have a minimum of ten different stacked producing intervals, and Lone Pine is able to produce from multiple intervals within an individual wellbore. Lone Pine currently has no significant near term expiries or drilling obligations in the Deep Basin, which has allowed Lone Pine to be flexible with its 2012 capital budget and defer significant natural gas investment until natural gas prices improve from their existing multi-year lows. In 2012, Lone Pine is allocating approximately 7% of its total capital budget, or approximately $15 million, to the Deep Basin where Lone Pine plans to focus primarily on recompletion opportunities.

Shales

As of December 31, 2011, Lone Pine had approximately 240,320 net acres in Quebec that are prospective for the Utica Shale. Natural gas produced from this area is in close proximity to major markets in Canada and the northeastern United States, which generally provides for premium product pricing compared to the NYMEX Henry Hub pricing. The Utica Shale is relatively shallow compared to other shale plays in North America, which Lone Pine believes will provide for an economic advantage relative to the drilling costs associated with developing the resource.

As of December 31, 2011, Lone Pine had approximately 52,995 net acres in the Liard Basin, located in the Northwest Territories, that are prospective for the Muskwa Shale. This is a newly developing natural gas shale play adjacent to the producing Horn River Basin. Lone Pine believes that its acreage in the Liard Basin is analogous to the Muskwa Shale in the Horn River Basin. Lone Pine’s acreage is located in close proximity to a pipeline in the Northwest Territories providing for the sale and distribution of any natural gas produced. In the third and fourth quarters of 2011, Lone Pine re-entered and recompleted a well in the Liard Basin and intends to submit an application to the National Energy Board to potentially continue the lease for up to 21 more years.

Reserves

The following table presents summary data with respect to Lone Pine’s estimated proved reserves as of the dates indicated. The estimated proved reserves as of December 31, 2011 presented in the table below were prepared by DeGolyer and MacNaughton, Lone Pine’s independent reservoir engineering firm, and the estimated proved reserves as of December 31, 2010 and 2009 presented in the table below were audited by DeGolyer and MacNaughton. In preparing its 2011 evaluation, DeGolyer and MacNaughton evaluated 100% of Lone Pine’s properties at December 31, 2011.

(1)           Lone Pine’s estimated proved reserves and standardized measure were determined using index prices for oil and natural gas and were held constant throughout the projected life of the properties. The unweighted arithmetic average first-day-of-the-month index prices for the prior 12 months were $96.13 per Bbl for oil and $4.15 per MMBtu for natural gas for NYMEX Henry Hub ($3.81 per MMBtu at AECO) at December 31, 2011, $79.81 per Bbl for oil and $4.38 per MMBtu for natural gas for NYMEX Henry Hub ($3.93 per MMBtu at AECO) at December 31, 2010, and $61.08 per Bbl for oil and $3.87 per MMBtu for natural gas for NYMEX Henry Hub ($3.46 per MMBtu at AECO) at December 31, 2009. The NYMEX and AECO prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price we receive at the point of sale.

(2)           Estimated proved reserves are based on anticipated sales volumes and do not contain those volumes of gas that Lone Pine expects to be consumed in operations, flared or injected.

(3)           In 2010 and 2009, Lone Pine sold certain non-core oil and gas properties that had estimated proved reserves of 13,795 MMcfe and 77,305 MMcfe, respectively.

(4)           As of December 31, 2011, Lone Pine had the following estimated proved developed producing reserves, estimated proved developed non-producing reserves and total estimated proved developed reserves.

5

(5)           As of December 31, 2011, Lone Pine had the following estimated proved undeveloped reserves.

(6)           PV-10, a non-GAAP financial measure, is an estimate of the present value of the estimated future net revenues from estimated proved oil and gas reserves at a date indicated after deducting estimated production and property taxes, future capital costs and operating expenses. The estimated future net revenues are discounted at an annual rate of 10%, before giving effect to income taxes, to determine their “present value.” PV-10 generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of taxes on estimated future net revenues. Lone Pine uses PV-10 as one measure of the value of its estimated proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. Lone Pine believes that securities analysts and rating agencies use PV-10 in similar ways. Lone Pine’s management believes PV-10 is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves. Lone Pine is unable to provide a reconciliation of PV-10 as of December 31, 2011 to standardized measure at this time because final income tax information for 2011 is not yet available. Below is a reconciliation of PV-10 to standardized measure as of December 31, 2010 and 2009:

(7)           As of December 31, 2011, Lone Pine’s PV-10 relating to its estimated proved developed producing reserves was $491.8 million, its PV-10 relating to its estimated proved developed non-producing reserves was $51.0 million and its PV-10 relating to its estimated proved undeveloped reserves was $158.1 million.

(8)           Standardized measure is an estimate of the present value of the estimated future net revenues from estimated proved oil and gas reserves at a date indicated after deducting estimated production and property taxes, future capital costs, operating expenses and estimated future income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s requirements, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using liquids and natural gas prices and operating costs at the estimation date in accordance with the SEC’s rules and regulations and are held constant for the life of the reserves.

As of December 31, 2011, Lone Pine had estimated proved reserves of 401 Bcfe. Lone Pine’s estimated proved reserves have a reserve life of twelve years, and its estimated proved developed reserves have a reserve life of six years. During 2011, Lone Pine added 52.4 Bcfe of estimated proved reserves through extensions and discoveries, which were primarily due to additional reserve bookings in the Evi area associated with positive drilling results and in the Narraway/Ojay fields associated with its acquisition of certain natural gas properties on April 29, 2011. As of December 31, 2011, proved undeveloped reserves, or PUDs, were estimated to be 187 Bcfe, or 47% of total estimated proved reserves, compared to 168 Bcfe, or 45% of total estimated proved reserves, as of December 31, 2010. The net increase of 19 Bcfe was primarily due to successful drilling results in the Evi area. The additional PUD bookings were primarily from direct offsets to existing wells. Lone Pine intends to convert the PUD reserves disclosed as of December 31, 2011 to proved developed reserves within five years of when they were initially disclosed as PUDs.

All estimates of proved reserves and related future net revenue disclosed in this Report have been prepared in accordance with applicable SEC rules and regulations.

6

Drilling Activities

The following table summarizes the number of wells drilled during the years ended December 31, 2011, 2010 and 2009, excluding any wells drilled under farmout agreements, royalty interest ownership or any other wells in which Lone Pine does not have a working interest. As of December 31, 2011, Lone Pine had 2 gross (2 net) wells in progress. Lone Pine’s 2011 horizontal drilling program achieved a 100% success rate, and its 2010 drilling program achieved a 100% success rate due to the multiple number of reservoirs its wells penetrated during drilling in these particular fields.

(1)           A non-productive well is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well; also known as a dry well (or dry hole).

Oil and Gas Wells

Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. The following table summarizes Lone Pine’s productive wells as of December 31, 2011 and December 31, 2010.

Hedging

As of February 3, 2012, Lone Pine had 25,000 MMBtu per day, representing approximately 40% of its forecasted 2012 average daily net natural gas production volumes hedged at an average NYMEX Henry Hub price of $5.09 per MMBtu and 3,000 Bbls per day of crude oil, representing approximately 55% of its forecasted 2012 average daily net crude oil production volumes hedged at $102.35 (as to 2,000 Bbls per day) and CDN$100.98 (as to 1,000 Bbls per day).

Item 9.01.              Financial Statements and Exhibits.

7

SIGNATURES

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

8

EXHIBIT INDEX

9