[CQP] Cheniere Partners: Q3 2026 Earnings Test Sabine Pass LNG Volumes and Margin

Cheniere Partners (CQP) is a publicly traded limited partnership that, through its subsidiaries, owns and operates the Sabine Pass LNG export terminal in Louisiana, earning its money by liquefying U.S. natural gas and selling it to long-term contract customers[1]. Third quarter 2026 (quarter ended September 30, 2026) results are scheduled for 2026-10-29, according to the Drillr earnings calendar[2]. The latest disclosed quarter is the second quarter of 2026: revenue was $2.583 billion, up 5% year over year; net income was $1.161 billion, up 110%; adjusted EBITDA was $983 million, up 35%; and the terminal loaded 108 cargoes and recognized 396 TBtu[3]. The partnership gives only full-year distribution guidance, and on August 6 it reconfirmed 2026 distributions of $3.10 to $3.40 per common unit, including a base distribution of $3.10[3]; on October 23 it declared a third-quarter distribution of $0.890 per unit, payable on November 13[4]. The three analysts compiled by Drillr average $2.557 billion for third-quarter revenue (range $2.379 billion to $2.744 billion) and $888 million for EBITDA (range $803 million to $973 million), while four analysts average $1.071 of net income per unit (range $0.932 to $1.210)[5]; these analysts' EBITDA definition may not match the partnership's adjusted EBITDA.

Three things matter most in these Cheniere Partners Q3 2026 earnings. The first is whether summer loadings and margin per MMBtu can hold the second quarter's 396 TBtu and roughly $2.48, because part of the second-quarter growth came from an easy comparison with a year-earlier period when two trains were in major maintenance, and the third quarter is the summer season, when liquefaction is naturally less efficient[1]. The second is whether net income stops swinging with global gas prices in the first full quarter after the IPM contracts moved to the normal purchases and normal sales (NPNS) exception in June, because quarterly net income jumped between $186 million and $1.161 billion in the first half, with almost the entire gap coming from non-cash fair value changes[6][7]. The third is whether operating cash flow can cover both the year's highest quarterly distribution of $0.890 and rising early capital spending on the first expansion phase, because first-half capital spending already exceeded the full-year 2025 total while federal approvals for the expansion are still outstanding[6][8].

Company Background and Business Structure

Sabine Pass is CQP's only operating asset and one of the largest LNG production facilities in the world. The 10-K describes six liquefaction trains with total production capacity of approximately 30 mtpa, three marine berths, five storage tanks with aggregate capacity of approximately 17 Bcfe, regasification capacity of approximately 4 Bcf/d, and the 94-mile Creole Trail pipeline that connects the terminal with several interstate pipelines[1]. CQP itself has no employees, directors or officers and is managed by its general partner, Cheniere Partners GP[1]; as of March 31, 2026, parent Cheniere owned 48.6% of the limited partner interest (239.9 million common units) as well as all of the general partner interest and the incentive distribution rights[9].

The business model is primarily fee-based, and customer pricing has two parts. Customers pay a fixed fee per MMBtu, part of which adjusts annually for inflation, plus a variable fee generally equal to 115% of Henry Hub; the fixed fee is payable even if a customer cancels or suspends cargo deliveries[1]. Through its SPAs and IPM agreements, the partnership has contracted approximately 85% of the liquefaction project's anticipated production to third parties through the mid-2030s, with a weighted average remaining life of about 13 years at the end of 2025[1] and about 12 years as of March 31, 2026[9]. Production not covered by long-term contracts is sold under an agreement to Cheniere Marketing, the parent's marketing arm[1].

The revenue mix and customer concentration are both clearly disclosed. In 2025, third-party LNG revenue was $8.200 billion, affiliate LNG revenue was $2.358 billion and regasification revenue was $136 million, for total revenue of $10.758 billion; the top five customers, BG (a Shell affiliate), Korea Gas Corporation, GAIL, Naturgy and TotalEnergies, accounted for 22%, 15%, 15%, 14% and 10% of revenue from external customers, or about 76% combined[1]. The IPM agreements are a different arrangement: producers sell gas to the partnership under long-term contracts priced on an international basis, and their long duration and overseas price linkage make their fair value swing sharply from quarter to quarter[7].

Financial History and Current Position

CQP's annual revenue has tracked gas prices rather than changes in capacity. According to Drillr financial data, revenue rose from $9.434 billion in 2021 to $17.206 billion in 2022, then fell back to $9.664 billion in 2023 and $8.704 billion in 2024, and net income was $2.987 billion in 2025 versus $2.510 billion in 2024. Revenue recovered to $10.758 billion in 2025; almost all of the roughly $2.1 billion increase came from higher pricing as Henry Hub rose, while planned major maintenance on two trains reduced revenue by $140 million through lower volumes, and Henry Hub monthly settlements averaged $3.43 per MMBtu during the year[1].

The 2025 cash flow statement shows a business with very low capital spending and very high distributions. Operating cash flow was $2.768 billion in 2025 (versus $2.968 billion in 2024), capital spending on property, plant and equipment was $199 million and distributions were $2.064 billion; total debt at year-end was $14.580 billion, down from $15.232 billion a year earlier[1].

In the first quarter of 2026 revenue grew while profit dropped sharply, and the cause was accounting rather than operations. Revenue was $3.600 billion, up 20%, adjusted EBITDA was $1.175 billion, up 13%, and the terminal loaded 112 cargoes and recognized 413 TBtu, yet net income was only $186 million, down 71%, because higher international gas prices and volatility produced $677 million of non-cash unfavorable changes on the IPM agreements[7]. Operating cash flow for the quarter was $910 million, capital spending was $31 million and total debt at the end of March was $14.327 billion[9].

For the first half ended June 30, 2026, both operations and cash were stronger than a year earlier. Second-quarter revenue was $2.583 billion and first-half revenue was $6.183 billion; second-quarter net income was $1.161 billion and first-half net income was $1.347 billion; first-half adjusted EBITDA was $2.158 billion (versus $1.764 billion), first-half recognized volumes were 809 TBtu (versus 756 TBtu), second-quarter depreciation and amortization was $174 million, and available liquidity was $2.337 billion at the end of June[3]. First-half operating cash flow was $1.609 billion (versus $1.223 billion), capital spending was $297 million (versus $128 million) and distributions were $1.007 billion, while the partnership issued $1.903 billion of debt and repaid $1.913 billion over the same period[6]. The quarterly distribution rose from $0.790 in the first quarter, including a $0.015 variable amount[7], to $0.820 in the second quarter, made up of a $0.775 base and a $0.045 variable amount[3].

Operating Model

The revenue equation depends on both loaded volumes and Henry Hub, but the two mean different things for profit. Total revenue equals third-party LNG revenue (a fixed fee plus a variable fee of about 115% of Henry Hub), affiliate LNG revenue, regasification revenue and other revenue[1]. In 2025 higher Henry Hub added about $2.1 billion to revenue while maintenance-related volume losses subtracted $140 million[1]; the second quarter of 2026 ran the other way, with higher production adding $305 million and lower Henry Hub pricing subtracting $167 million[6]. Henry Hub enters revenue and feedstock cost in the same quarter, so it mainly changes the size of revenue and has a smaller direct effect on profit.

Operating income equals revenue minus feedstock cost, operating and maintenance expense, and depreciation and amortization, plus or minus fair value changes on commodity derivatives. Feedstock cost broadly follows U.S. gas prices and rose by about $1.9 billion in 2025 as those prices increased, largely offset by the variable fee[1]; depreciation and amortization runs at about $174 million a quarter and is fairly stable[3]. Management uses adjusted EBITDA to strip out derivative fair value changes: in the first quarter adjusted EBITDA was $1.175 billion against net income of $186 million[7], and in the second quarter adjusted EBITDA was $983 million against net income of $1.161 billion, with the partnership attributing the roughly $257 million year-over-year EBITDA increase to higher total margins per MMBtu driven by higher recognized volumes[3]. Dividing adjusted EBITDA by recognized volumes implies a combined margin of about $2.07 per MMBtu in the second quarter of 2025, about $2.85 in the first quarter of 2026 and about $2.48 in the second quarter.

The cash equation turns quarterly operating results into distributions almost directly. Because customers' fixed fees do not disappear when cargoes are cancelled, operating cash flow is relatively stable, and the partnership agreement requires CQP to distribute all available cash within 45 days after each quarter, defined as cash on hand at quarter-end less reserves set by the general partner[1]. Once the quarterly distribution exceeds $0.638 per unit, increments are split 50% to unitholders and 50% to the general partner[1], so the higher the variable distribution, the larger the share Cheniere collects through its general partner interest. Distributions arrive one quarter later; the third-quarter payment of $0.890, for example, was declared on October 23 and is payable on November 13[4].

Seasonality is the timing variable that links these three equations. The 10-K explains that the liquefaction project can produce more in cooler months than in summer, and that the partnership typically schedules major maintenance during shoulder months in the second and third quarters to limit the effect on annual results[1]. Third-quarter loadings are therefore held down by summer temperatures and also depend on whether maintenance was scheduled, and that outcome flows into adjusted EBITDA in the same quarter and into the distribution early in the next one.

Industry and Competitive Position

Sabine Pass competes on the cost gap between U.S. and overseas gas prices. As one of the largest LNG production facilities in the world, it supplies LNG on a Henry Hub cost base and competes with LNG priced on other indices and with alternative energy sources[1]. European LNG demand rose about 27% in 2025 to a record of roughly 125 mtpa, while Asian LNG consumption fell about 4% to 270 mtpa[1].

Geopolitical conflict in 2026 has tightened the near-term market, but longer-term competition is intensifying. Parent Cheniere said on its second-quarter call that constrained shipping through the Strait of Hormuz removed about 18 million tons of global LNG supply in the second quarter, and that U.S. LNG exports shifted decisively to Asia, reaching a quarterly record of about 11 million tons[10]. The same call noted that more than 100 mtpa of new capacity has reached a final investment decision since 2025 without being fully contracted, which means pricing competition for future long-term contracts will be tougher[10].

This comparison has clear limits. CQP does not hold its own earnings call, so management's market views come from parent Cheniere's call, and the available material provides no directly comparable peer revenue or profit data. The parent also flagged that variability in the nitrogen content of Permian Basin feed gas creates operating challenges, which management has addressed with several mitigation steps[10]; this is an operating constraint specific to Sabine Pass relative to other gas sources.

Core Debates

Without major maintenance this summer, can Sabine Pass hold its second-quarter loading volumes and margin per MMBtu?

This question directly determines CQP's profit and variable distribution. Sabine Pass is the partnership's only operating asset and customers pay fixed fees under long-term contracts, so profit depends mainly on actual loadings and on how much the excess volumes sold to Cheniere Marketing earn[1]. Second-quarter loadings were 13% higher than a year earlier, mainly because two trains were in maintenance in the prior-year quarter, while the third quarter is the summer season, when liquefaction is naturally less efficient, so holding volumes will determine adjusted EBITDA and the distributions that follow.

The evidence shows second-quarter unit margin below the first quarter's but well above the prior-year level. The terminal recognized 396 TBtu across 108 cargoes in the second quarter, versus 351 TBtu and 98 cargoes a year earlier, and adjusted EBITDA was $983 million, versus $726 million[3]; the first quarter delivered 413 TBtu and $1.175 billion[7]. On those figures, combined margin per MMBtu was about $2.48 in the second quarter, about $2.85 in the first quarter and about $2.07 in the second quarter of 2025. The parent said on its call that realized and forecast marketing margins for the rest of 2026 are higher and that less than 50 TBtu of 2026 production remains unsold[10].

The financial transmission is short, but an alternative explanation is equally plausible. Recognized volumes multiplied by combined margin per MMBtu (set by SPA fixed fees and Cheniere Marketing's international market margins) produce adjusted EBITDA, which then flows into operating cash flow and the variable distribution; Henry Hub enters both revenue and feedstock cost and has a smaller effect on profit. The alternative view is that the second-quarter improvement mainly reflects the low base created by last year's maintenance rather than a durable margin gain; if summer derates or outages hit the third quarter, EBITDA would fall back below $900 million.

What remains unresolved is whether summer volumes and international margins can hold at the same time, and the third-quarter report will answer it directly. The points to watch are whether third-quarter recognized LNG volumes stay at or above about 385 TBtu, whether adjusted EBITDA divided by volumes stays at or above about $2.48 per MMBtu, and whether the 10-Q discloses any planned maintenance or unplanned outages in the quarter. If summer derates or outages push volumes below 360 TBtu, or weaker international margins pull margin per MMBtu back below $2.20, the current understanding would be weakened.

After the IPM contracts moved to normal purchases and normal sales accounting, will CQP's net income stop swinging with global gas prices?

This question determines whether readers can judge CQP's operations directly from its income statement. Net income swung between $186 million and $1.161 billion in the first half of 2026, while adjusted EBITDA stayed between $983 million and $1.175 billion[7][3], and almost the entire difference came from non-cash fair value changes on the IPM agreements. The partnership changed its accounting in June, making the third quarter the first full quarter under the new treatment.

The evidence shows a clear source of volatility and a change in how it is treated. In the first quarter, conflict in the Middle East pushed up international gas prices and volatility, the IPM agreements produced $677 million of non-cash unfavorable changes, the commodity derivative fair value line in the adjusted EBITDA reconciliation was a $640 million loss, and net income fell 71%[7]; in the second quarter the spread between global and U.S. prices narrowed, the same line turned into a $526 million gain, and net income rose 110%[3]. The 10-Q disclosed that in June 2026 the partnership designated the NPNS scope exception for its IPM agreements, so they are no longer accounted for as derivatives, and their fair value was a $394 million liability at the end of 2025[6]; the parent said on its call that the designation covered 75% of IPM agreement volumes on a consolidated Cheniere basis[10].

The financial transmission shifts from fair value swings to steady amortization, though the volatility may not disappear entirely. Changes in the spread and volatility between global and U.S. gas prices used to pass through IPM fair value into non-cash gains and losses in cost of sales and then straight into net income; after the NPNS designation, this becomes amortization of deferred assets and liabilities, which was a $5 million charge in the second quarter and does not affect adjusted EBITDA or cash[3]. In the alternative scenario, the portion still carried at fair value and North American delivery basis derivatives keep producing quarterly swings in the $100 million to $200 million range, as these other agreements did with a $145 million unfavorable change in the second quarter[6], so net income becomes less volatile rather than stable.

What remains unresolved is how much contract volume has been designated at the CQP level and how large the remaining derivatives are. The points to watch are whether the commodity derivative fair value line in the adjusted EBITDA reconciliation shrinks to within about $150 million, the quarterly amount of NPNS deferred asset and liability amortization, and whether the 10-Q states the share of CQP-level IPM agreements that has been designated. If derivative fair value changes still exceed $300 million, net income will keep diverging from operating results.

With the third-quarter distribution at its highest level this year, can CQP fund both its payout and the first phase of the Sabine Pass expansion?

This question goes to CQP's role as a vehicle for distributing cash. Full-year distribution guidance is the partnership's only quantitative guidance, and the parent said on its call that the $3.10 to $3.40 range was maintained to accommodate early funding for the Sabine Pass expansion[10]. The first expansion phase is already under a limited notice to proceed, capital spending will rise sharply after a final investment decision, and the room for variable distributions depends on how much operating cash flow remains after capital spending and debt service.

The evidence shows first-half cash comfortably covering distributions and capital spending, while capital spending is climbing quickly. First-half 2026 operating cash flow was $1.609 billion, capital spending was $297 million and distributions were $1.007 billion, with $1.903 billion of debt issued and $1.913 billion repaid over the same period[6]; subtracting the first quarter's $910 million of operating cash flow and $31 million of capital spending[9] implies about $699 million of operating cash flow and about $266 million of capital spending in the second quarter. In May the partnership priced $1 billion of 5.350% notes due 2036 and $750 million of 6.050% notes due 2056[11], with proceeds used to redeem the SPL senior notes due 2027 and to fund part of the limited notice to proceed for the first expansion phase[6]. The third-quarter distribution of $0.890 declared on October 23[4], together with $0.790 and $0.820 in the first two quarters, brings the year-to-date total to $2.50.

The financial transmission is a chain that deducts capital spending and debt service before arriving at distributions. Operating cash flow minus capital spending (currently mainly work under the limited notice to proceed for the first expansion phase) and debt service reserves yields available cash, which becomes the per-unit distribution, and 50% of any amount above $0.638 goes to the general partner[1]. The first phase comprises a single train, Train 7, and a boil-off gas re-liquefaction unit, with expected total production capacity of over 6 mtpa including estimated debottlenecking, and the partnership anticipates reaching a final investment decision by early 2027[8]; the lump-sum turnkey EPC contract with Bechtel is $4.7 billion, and regulatory approvals are anticipated by the end of 2026[10]. Capital spending after the final investment decision would be funded with new debt and retained cash. The alternative explanation is that the higher variable distribution reflects a stronger third-quarter cash result, but as the final investment decision approaches, the general partner may raise reserves in the fourth quarter, leaving the full-year distribution in the middle of the range rather than continuing to climb.

What remains unresolved is the pace of approvals and the fourth-quarter reserve decision, and both will show up in later disclosures. As of June 30, the 10-Q showed the FERC environmental assessment and the non-FTA export authorization still pending, the EPC contract signed, and the final investment decision timed for 2026/2027[6]. The points to watch are whether year-to-date operating cash flow covers distributions and capital spending, whether the $3.10 to $3.40 distribution guidance is maintained or raised, and whether FERC and DOE approvals for the first phase advanced during the third quarter. If distributions have to be funded with net new borrowing, if full-year guidance is cut, or if delayed approvals push the final investment decision beyond early 2027, the current understanding would be weakened.

Risks and Falsifiers

Customer concentration and contract expiry are the most fundamental revenue risk. Five SPA customers contribute about 76% of external revenue, with BG, Korea Gas Corporation, GAIL, Naturgy and TotalEnergies at 22%, 15%, 15%, 14% and 10%, contracts cover about 85% of anticipated production through the mid-2030s, and third-party LNG revenue was $8.200 billion in 2025[1]; whether contracts are renewed when they expire depends on how the cost of U.S. LNG compares with other gas sources. As long as quarterly reports show contract coverage held or rising and no customer default or fixed-fee cancellation is disclosed, this risk remains a distant one.

Governance and value-sharing risk determines how much cash unitholders actually receive. CQP has no employees and is managed by a general partner controlled by Cheniere[1], which also holds 48.6% of the limited partner interest and all incentive distribution rights[9]; once quarterly distributions exceed $0.638, 50% of each increment goes to the general partner, which also decides capital spending and reserves. Within the third-quarter distribution of $0.890, the amount above $0.638 is split evenly between unitholders and the general partner[4], and distributions paid in 2025 totaled $2.064 billion[1]. If the general partner maintains full-year distribution guidance and funds the expansion without cutting the base distribution, this risk has not turned into an actual loss.

Operational disruption risk hits loadings and adjusted EBITDA directly. The 10-K lists hurricanes and adverse weather among hazards that could cause significant delays[1], the parent has flagged operating challenges from variable nitrogen content in Permian Basin feed gas[10], and summer heat also lowers liquefaction efficiency. At the second quarter's roughly $2.48 per MMBtu, every 10 TBtu not loaded would cut adjusted EBITDA by about $25 million. If third-quarter recognized volumes stay at or above about 385 TBtu, this risk did not materialize in the quarter.

Accounting volatility risk affects net income, not cash. If NPNS covers only part of the IPM volumes, or other derivatives become more volatile, net income will keep swinging sharply; commodity derivative fair value changes were a $640 million loss in the first quarter of 2026[7] and a $526 million gain in the second[3], each equal to more than half of that quarter's adjusted EBITDA. If the absolute value of that reconciliation line stays within about $150 million in the third quarter, the accounting change will have taken effect.

Expansion risk would squeeze both variable distributions and the balance sheet. Approval delays or cost increases on the first expansion phase would absorb cash that could otherwise go to unitholders and add debt; the first-phase EPC contract on a consolidated Cheniere basis is $4.7 billion[10], and CQP's capital spending in the first half of 2026 already reached $297 million[6], above the $199 million for all of 2025[1]. If the third-quarter 10-Q shows approvals advancing and operating cash flow covering distributions and capital spending, this risk remains manageable for now.

What to Watch Next

• Summer loadings and unit margin: third-quarter recognized LNG volumes against the second quarter's 396 TBtu across 108 cargoes, plus any maintenance or outages. At or above about 385 TBtu holds the baseline; below 360 TBtu weakens it.
• Implied margin per MMBtu: adjusted EBITDA divided by volumes against about $2.48 in the second quarter. At or above about $2.48 holds; a fall back below $2.20 weakens it.
• Net income volatility after NPNS: the commodity derivative fair value line, a $526 million gain in the second quarter and a $640 million loss in the first, plus the NPNS amortization amount. Within about $150 million confirms the change is working; above $300 million weakens it.
• Distributions and expansion funding: operating cash flow and capital spending against first-half levels of $1.609 billion and $297 million. Coverage from internal cash confirms; reliance on net new borrowing weakens.
• Guidance and approvals: the $3.10 to $3.40 full-year distribution guidance and the pending FERC and DOE approvals. Guidance maintained and approvals advancing confirm; a cut, or a final investment decision pushed beyond early 2027, weakens.

Conclusion

CQP's business comes down to one terminal, one set of fee-based contracts and one rule for paying out cash. Sabine Pass's six trains sell LNG for a fixed fee plus about 115% of Henry Hub, with about 85% of anticipated production contracted through the mid-2030s[1]; first-half 2026 adjusted EBITDA was $2.158 billion[3], operating cash flow was $1.609 billion and capital spending was $297 million[6], and the third-quarter distribution rose to $0.890[4]. The central unresolved relationship is whether the second quarter's unit margin of about $2.48 per MMBtu and 396 TBtu of loadings can hold through a summer without major maintenance, and keep supporting the variable distribution as expansion spending rises.

On outside views, since second-quarter results were published on August 6, 2026, no independent analysis focused on CQP itself with a verifiable publisher, author and date has appeared, so no outside interpretation is summarized here. The only market perspectives available come from parent Cheniere's earnings call and from the numerical ranges of the three to four analysts compiled by Drillr[5]; the latter are numerical aggregates for a single quarter and are no substitute for independent analysis of the three debates above.

The combination that would materially strengthen the current understanding is third-quarter loadings at or above about 385 TBtu, margin per MMBtu at or above about $2.48, a commodity derivative reconciliation line within about $150 million, year-to-date operating cash flow covering distributions and capital spending, and expansion approvals advancing on schedule. Conversely, loadings below 360 TBtu, unit margin back below $2.20, derivative swings still above $300 million, or distributions that depend on new debt would clearly weaken it.

Sources

[1] CQP FY2025 10-K filed 2026-02-26 · 2026-02-26 · 10-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=10-K&dateb=&owner=include&count=40

[2] CQP earnings calendar updated 2026-10-26 · 2026-10-26 · Drillr earnings calendar

[3] CQP Q2 2026 8-K filed 2026-08-06 · 2026-08-06 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=8-K&dateb=&owner=include&count=40

[4] CQP 8-K filed 2026-10-23 · 2026-10-23 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=8-K&dateb=&owner=include&count=40

[5] Drillr analyst estimates CQP Q3 2026 retrieved 2026-10-26 · 2026-10-26 · Drillr analyst estimates · https://gateway.drillr.ai/mcp/private

[6] CQP Q2 2026 10-Q filed 2026-08-06 · 2026-08-06 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=10-Q&dateb=&owner=include&count=40

[7] CQP Q1 2026 8-K filed 2026-05-07 · 2026-05-07 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=8-K&dateb=&owner=include&count=40

[8] CQP 8-K filed 2026-05-28 · 2026-05-28 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=8-K&dateb=&owner=include&count=40

[9] CQP Q1 2026 10-Q filed 2026-05-07 · 2026-05-07 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=10-Q&dateb=&owner=include&count=40

[10] Cheniere Energy Q2 2026 earnings call 2026-08-06 · 2026-08-06 · earnings-call · https://gateway.drillr.ai/mcp/private

[11] CQP 8-K filed 2026-05-27 · 2026-05-27 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001383650&type=8-K&dateb=&owner=include&count=40